Grizzly Energy 10K 2017 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



(Mark One)
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2017

Or

p		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to .

Commission File Number 001-33756

Vanguard Natural Resources, Inc.

(Exact Name of Registrant as Specified in Its Charter)



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

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

Telephone Number: (832) 327-2255

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

Securities registered pursuant to Section 12(g) of the Act:

Warrants to purchase common stock, par value $0.001 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.



		Yes o		No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



		Yes o		No x

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 x		No o

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 x		No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.



				o

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



Large accelerated filer o		Accelerated filer o
Non-accelerated filer o (Do not check if smaller reporting company)		Smaller reporting company x
		Emerging growth company o

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 Act).



		Yes o		No x

The aggregate market value of the voting and non-voting equity securities held by non-affiliates of the registrant, based on the closing price of the registrant’s predecessor’s common units representing limited liability company interests on the last business day of the registrant’s predecessor’s most recently completed second quarter, June 30, 2017, was approximately $5,486,659.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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 x		No o

There were 20,100,178 shares of the registrant’s common stock, $0.001 par value, outstanding as of March 16, 2018.

Documents Incorporated by Reference:

None.

Vanguard Natural Resources, Inc.

TABLE OF CONTENTS



	Caption	Page

Glossary of Terms
	PART I
Item 1.	Business	2
Item 1A.	Risk Factors	30
Item 1B.	Unresolved Staff Comments	47
Item 2.	Properties	48
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosures	52

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
Item 6.	Selected Financial Data	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	61
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
Item 8.	Financial Statements and Supplementary Data	88
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	144
Item 9A.	Controls and Procedures	144
Item 9B.	Other Information	144

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	145
Item 11.	Executive Compensation	152
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	159
Item 13.	Certain Relationships and Related Transactions, and Director Independence	162
Item 14.	Principal Accounting Fees and Services	164

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	165
	Signatures	168
Item 16.	Form 10-K Summary	168

Forward-Looking Statements

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

These 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 Annual 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 Part I, Item 1A. These factors and risks include, but are not limited to:


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


•	our ability to meet our liquidity needs;


•	our ability to access the public capital markets;


•	risks relating to any of our unforeseen liabilities;


•	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 exploration 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 Annual Report are based on information available to us on the date of this Annual 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 Annual Report.

Reservoir engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:



/day	= per day	Mcf	= thousand cubic feet

Bbls	= barrels	Mcfe	= thousand cubic feet of natural gas equivalents

Bcf	= billion cubic feet	MMBbls	= million barrels

Bcfe	= billion cubic feet equivalents	MMBOE	= million barrels of oil equivalent

BOE	= barrel of oil equivalent	MMBtu	= million British thermal units

Btu	= British thermal unit	MMcf	= million cubic feet

MBbls	= thousand barrels	MMcfe	= million cubic feet of natural gas equivalents

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

When we refer to oil, natural gas and natural gas liquids 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 Annual Report to the “Successor” are to Vanguard Natural Resources, Inc., formerly known as VNR Finance Corp., and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), VNR Holdings, LLC (“VNRH”), Vanguard Operating, LLC (“VO”), Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Acquisition Partnership II, L.P. (“ERAP II”).

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

References in this Annual 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.

PART I

ITEM 1. BUSINESS

Overview

We are an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States. Through our operating subsidiaries, as of December 31, 2017, we own properties and oil and natural gas reserves primarily located in nine operating basins:


•	the Green River Basin in Wyoming;


•	the Piceance Basin in Colorado;


•	the Permian Basin in West Texas and New Mexico;


•	the Arkoma Basin in Arkansas and Oklahoma;


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


•	the Big Horn Basin in Wyoming and Montana;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

The Predecessor was formed in October 2006 as a Delaware limited liability company named Vanguard Natural Resources, LLC and completed its initial public offering in October 2007. On August 1, 2017, we emerged from bankruptcy and reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. See “Emergence from Voluntary Reorganization under Chapter 11 Proceedings” included under Part I, Item 1 of this Annual Report for additional information.

Following the completion of the financial restructuring on August 1, 2017 (Notes 1 and 3 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report), the Company had 20.1 million shares of its common stock outstanding. The Company’s shares of common stock and two series of warrants are traded and quoted on the OTCQX market (which is operated by OTC Markets Group, Inc.) under the symbols VNRR, VNRRW and VNRWW, respectively.

Recent Developments

Management Changes

On January 15, 2018, the Company announced a number of changes to its management team. On that date, Scott W. Smith, the President and Chief Executive Officer of the Company, stepped down as President and Chief Executive Officer and from his position on the board of directors of the Company (the “Board”), effective immediately. The Company promoted R. Scott Sloan to President and Chief Executive Officer, effective January 17, 2018. In addition, the Company appointed Ryan Midgett as the Chief Financial Officer and Patty Avila-Eady as the Chief Accounting Officer of the Company. Britt Pence, the Company’s Executive Vice President of Operations, has also agreed to step down, effective on or before June 29, 2018 or such other time as mutually agreed with the Company.

Asset Divestiture Update

In 2018, the Company has launched marketing processes to initiate and explore the divestment of certain of its assets in Wind River (Wyoming) and its deep-rights leasehold acreage in Ward County, Texas. The Wind River properties consist of producing properties and leasehold rights in Fremont and Natrona Counties, Wyoming with current production of approximately 7,000 Mcf equivalent per day (84% gas). The Ward County properties consist of producing properties and certain deep-rights leasehold acreage in Ward County, Texas, with current production of approximately 300 Bbl equivalent per day (73% oil). Additionally, the Company is exploring and marketing additional asset divestitures, including a substantial

portion of its Gulf Coast assets as well as certain properties located in the Green River Basin excluding properties in the Pinedale field.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

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

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

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

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

Plan of Reorganization

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

•

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

•

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

outstanding under the Successor Credit Facility as of the Effective Date was $730.0 million. The Successor Credit Facility also includes an additional $125.0 million senior secured term loan (the “Term Loan”). The holders of claims under the Predecessor Credit Facility received a recovery, consisting of a cash pay down and their pro rata share of the Successor Credit Facility. The next borrowing base redetermination is scheduled for August of 2018;


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


•	The Predecessor’s Senior Notes were cancelled and the holders of the Senior Notes received their pro rata share of 97.0% (subject to dilution by the other transactions referred to in this section) of the Common Stock, in full and final satisfaction of their claims;

•

The Predecessor completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $275.0 million of gross proceeds. The rights offering resulted in subscriptions for 18.1 million shares of Successor common stock, representing approximately 89.92% of outstanding shares of Common Stock, to holders of claims arising under the Senior Notes and to the Backstop Parties;

•

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


•	Additional shares of Common Stock, representing 10% of outstanding shares of Common Stock on a fully diluted basis, were authorized for issuance under the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”);

•

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


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

•

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


•	By operation of the Final Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. A new board was established for the Successor Company;


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


•	The Successor issued 20.1 million shares of common stock, $0.001 par value (“Common Stock”).

Each of the foregoing percentages of equity in the Successor were as of August 1, 2017 and are subject to dilution from the exercise of the Warrants described above, the MIP discussed further in Item 8. Financial Statements and Supplementary Data, Note 11, “Stockholders’ Equity (Members’ Deficit),” and other future issuances of equity interests.

Listing on the OTCQX Market

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

Accounting Policies

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

•

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


•	We changed our method of accounting for natural gas and oil properties from the full cost method of accounting to the successful efforts method of accounting;


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


•	We changed from a pass-through entity for tax purposes to a C-corporation and, accordingly, a taxable entity.

Fresh-Start Accounting

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

We adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the fair value of the Successor Company’s total assets or the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to “Plan of Reorganization” above for the terms of our reorganization under the Final Plan. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Final Plan, our consolidated financial statements subsequent to July 31, 2017 are not comparable to our consolidated financial statements prior to July 31, 2017, as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Proved Reserves

Our total estimated proved reserves at December 31, 2017 were 1,821.5 Bcfe, of which approximately 13% were oil reserves, 75% were natural gas reserves and 12% were NGLs reserves. Of these total estimated proved reserves, approximately 67% were classified as proved developed. At December 31, 2017, estimated future cash inflows from estimated future production of proved reserves were computed in accordance with SEC (as defined under “Oil, Gas and NGLs Data - Estimated Proved Reserves) rules using the average oil, natural gas and NGLs price based upon the 12-month unweighted

average of first-day-of-the-month price of $51.22 per barrel of crude oil, $2.99 per MMBtu for natural gas, and $19.24 per barrel of NGLs, as described under “Oil, Gas and NGLs Data - Estimated Proved Reserves.”

At December 31, 2017, we owned working interests in 11,287 gross (3,902 net) productive wells. Our operated wells accounted for approximately 43% of our total estimated proved reserves at December 31, 2017. Our average net daily production was 374,063 Mcfe/day for the year ended December 31, 2017 and was 362,011 Mcfe/day for the fourth quarter of 2017. Our average proved reserves-to-production ratio, or average reserve life, is approximately thirteen years based on our total proved reserves as of December 31, 2017 and our fourth quarter 2017 annualized production.

Business Strategies

The Company is currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner by executing the following business strategies:


•	Manage our portfolio of assets actively, including divesting certain non-core assets to focus on the development of our core inventory of undeveloped locations, specifically in the Pinedale and Mamm Creek fields, located in the Green River Basin and the Piceance Basin, respectively, and Arkoma Woodford;


•	Continue to efficiently operate several of our long-lived, low decline oil and gas fields for production and cash flow;


•	Pursue a capital structure which affords financial flexibility; and


•	Use hedging strategies to reduce the volatility in our revenues resulting from changes in oil, natural gas and NGLs prices.

Properties

As of December 31, 2017, through certain of our subsidiaries, we own interests in oil and natural gas properties located in nine operating basins. The following table presents the production for the year ended December 31, 2017 and the estimated proved developed reserves for each operating area:



	2017 Net Production
	Natural Gas	Oil	NGLs	Total	Net Estimated Proved Reserves	PV-10 Value ^(b)
	(MMcf)	(MBbls)	(MBbls)	(MMcfe)	(MMcfe)	(in millions)
Green River Basin	38,303	359	549	43,754	750,083	$	374.2
Piceance Basin	18,285	199	1,345	27,544	292,424	$	222.4
Permian Basin	5,872	1,272	557	16,849	144,095	$	164.7
Arkoma Basin	15,165	3	188	16,309	337,571	$	137.4
Gulf Coast Basin	5,263	652	481	12,057	133,731	$	120.7
Big Horn Basin	209	777	96	5,446	83,348	$	119.5
Williston Basin^(a)	222	363	4	2,429	—	$	—
Anadarko Basin	1,837	130	43	2,874	36,300	$	33.4
Wind River Basin	2,552	13	57	2,970	25,976	$	14.6
Powder River Basin	6,302	—	—	6,302	18,015	$	7.9
Total	94,010	3,768	3,320	136,534	1,821,543	$	1,194.8


(a)	In December 2017, we completed the sale of our oil and natural gas properties in the Williston Basin in North Dakota and Montana (“Williston Divestiture”).

(b)

Present Value of Future Net Reserves (“PV-10”) is the present value of estimated future net revenues to be generated from the production of proved reserves, calculated net of estimated production costs and future development costs, using prices based on the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”), and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows. We believe the PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by analysts, banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific properties without regard to the owner's income tax position. We use the PV-10 Value for comparison against our debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment from our oil and natural gas properties. For our presentation of the standardized measure of discounted future net cash flows, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report.

The following is a description of our properties by operating basin:

Green River Basin Properties

Our Green River Basin properties are primarily comprised of assets in the Pinedale and Jonah fields of southwestern Wyoming. Production in these fields is dominated by natural gas and NGLs from tight sands formations. The Pinedale field lies at depths anywhere between 11,000 to 14,000 feet with similar depths in the adjacent Jonah field. Additionally, we have Green River Basin properties located in the Hay Reservoir, Great Divide, Siberia Ridge, Wamsutter, Echo Springs and Standard Draw fields in southwestern Wyoming. These gas/condensate fields produce from stacked cretaceous aged tight sandstones within the Lewis and Almond/Mesaverde intervals between 8,000 and 12,000 feet deep. Our properties located in south central Wyoming in the Sierra Madre field produce predominately oil from fractured cretaceous aged Niobrara limestone (between 5,000 and 6,000 feet) and conventional Shannon sandstone (between 3,500 and 4,000 feet). As of December 31, 2017, our Green River Basin properties consisted of 126,420 gross (35,170 net) leasehold acres. During 2017, the Green River Basin properties produced approximately 43,754 MMcfe of which 88% was natural gas. At December 31, 2017, the properties had total proved reserves of approximately 750,083 MMcfe or 41% of our total estimated proved reserves at year end, of which 47% were proved developed and 87% were natural gas.

Piceance Basin Properties

The Piceance Basin is located in northwestern Colorado. Our Piceance Basin properties, which we operate, are located in the Gibson Gulch. The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of approximately 6,000 to 8,000 feet. As of December 31, 2017, our Piceance Basin properties consisted of 25,320 gross (17,355 net) leasehold acres. During 2017, our properties in the Piceance Basin produced approximately 27,544 MMcfe, of which 66% was natural gas. At December 31, 2017, the Piceance Basin properties accounted for approximately 292,424 MMcfe or 16% of our total estimated proved reserves at year end, of which 94% were proved developed and 66% were natural gas.

Permian Basin Properties

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States extending over West Texas and southeast New Mexico. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. Our Permian Basin properties are located in several counties which extend from Eddy County, New Mexico to Ellis County, Texas and encompass hundreds of fields with multiple producing intervals. The majority of our producing wells in the Permian Basin are mature oil wells that also produce high-Btu casinghead gas with significant NGLs content. These properties primarily produce at depths ranging from 2,000 feet to 12,000 feet. As of December 31, 2017, our Permian Basin properties consisted of 339,888 gross (232,704 net) leasehold acres. These acreage totals include a reduction of approximately 4,467 gross (2,778 net) acres made during 2017. This adjustment is related to deep rights underlying certain leasehold acreage in Eddy and Lea Counties in New Mexico included in acreage totals within our Supplemental Emergence Presentation dated November 9, 2017, made available on our website. Upon further examination of title and related records, it was discovered that the deep rights related to such 4,467 gross (2,778 net) acres were held by a third party, with our interest therein being limited to an overriding royalty interest. During 2017, our Permian Basin operations produced approximately 16,849 MMcfe, of which 65% was oil, condensate and NGLs. At December 31, 2017, these properties

accounted for approximately 144,095 MMcfe or 8% of our total estimated proved reserves at year end, of which 99% were proved developed and 64% were oil, condensate and NGLs.

Arkoma Basin Properties

Our Arkoma Basin properties include properties in the Woodford Shale and Jackfork formations, located in eastern Oklahoma, the Fayetteville Shale, located in Arkansas, and royalty interests and non-operated working interest in both states. As of December 31, 2017, our Arkoma Basin properties consisted of 389,023 gross (179,381 net) leasehold acres. During 2017, the Arkoma Basin properties produced approximately 16,309 MMcfe, of which 93% was natural gas. At December 31, 2017, the properties had total proved reserves of approximately 337,571 MMcfe or 19% of our total estimated proved reserves at year end, of which 55% were proved developed and 96% were natural gas.

Gulf Coast Basin Properties

Our Gulf Coast Basin properties include properties in the onshore Gulf Coast area, North Louisiana, Alabama, East Texas, South Texas and Mississippi.

Production from our North Louisiana properties comes from the East Haynesville and Cotton Valley fields. These properties include multiple productive zones including Cotton Valley, James Lime, Pettet, Haynesville, Smackover and Hosston. East Haynesville is located in Claiborne Parish, Louisiana and lies at a depth of approximately 9,000 to 11,000 feet. The Cotton Valley field is located in Webster Parish, Louisiana and produces from an average depth of 11,000 feet.

Our Alabaman properties include the Big Escambia Creek, Flomaton and Fanny Church fields located in Escambia County, Alabama. These fields produce from either the Smackover or Norphlet formations at depths ranging from approximately 15,000 to 16,000 feet. The Fanny Church field is located two miles east of Big Escambia Creek. The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet. The Smackover and Norphlet reservoirs are sour gas condensate reservoirs which produce gas and fluids containing a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Company-operated Big Escambia Creek Treating facility and the effluent gas is further processed for the removal of natural gas liquids in the Big Escambia Creek Gas Processing facility. The operation of the wells and the facility is closely connected, and we are the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and NGLs, we also market elemental sulfur.

Our South Texas properties primarily are located in Hidalgo, LaSalle, Live Oak and Webb Counties. Most of the production is high Btu gas that is produced from the Olmos and Escondido sand formations from a depth averaging 7,500 feet.

Our East Texas producing properties include the Fairway (James Lime Unit) field in Henderson and Anderson counties, and produces from an average depth of 10,000 feet. The Silsbee field is in Hardin County, Texas. Most of the Silsbee production is oil produced from the Yegua formation.

We operate the majority of our Mississippi properties which are located in the Mississippi Salt Basin. Most of our production comes from the Parker Creek field in Jones County, Mississippi. Our production is mainly oil that produces from the Hosston Formation from a depth ranging from approximately 13,000 feet to 15,000 feet. Our other Mississippi properties are located in Covington, Jasper, Clarke, Leflore, Jefferson Davis, Wayne and Walthall Counties.

As of December 31, 2017, our Gulf Coast Basin properties consisted of 161,554 gross (69,746 net) leasehold acres. During 2017, the Gulf Coast Basin properties produced approximately 12,057 MMcfe, of which 56% were oil, condensate and NGLs. At December 31, 2017, these properties accounted for approximately 133,731 MMcfe or 7% of our total estimated proved reserves at year end, of which 78% were proved developed and 50% were natural gas.

Big Horn Basin Properties

The Big Horn Basin is a prolific basin which is characterized by oil and natural gas fields with long production histories and multiple producing formations.

Our Elk Basin field is located in Park County, Wyoming and Carbon County, Montana. We operate all of our properties in the Elk Basin area, which includes the Embar-Tensleep, Madison and Frontier formations as discussed below.

Embar-Tensleep Formation. Production in the Embar-Tensleep formation is being enhanced through a tertiary recovery technique involving effluent gas, or flue gas, from a natural gas processing facility located in the Elk Basin field. From 1949 to 1974, flue gas was injected into the Embar-Tensleep formation to increase pressure and improve production of resident hydrocarbons. Currently, we still use flue gas injection to maintain and improve production within this formation and have recently initiated a fresh water injection pilot on top of the structure. Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 5,100 to 6,600 feet.

Madison Formation. We continue to operate an active water injection program which is used to enhance production in the Madison formation. The wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,400 to 7,000 feet.

Frontier Formation. The Frontier formation is being produced through primary recovery techniques. The wells in the Frontier formation of the Elk Basin field are typically drilled to a depth of 1,400 to 2,700 feet.

We operate and own a 62% interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s. ExxonMobil Corporation (“Exxon”) owns a 34% interest in the Elk Basin natural gas processing plant, and other parties own the remaining 4% interest. This plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from Elk Basin fields.

We also operate and own the Wildhorse pipeline system, which is an approximately 12-mile natural gas gathering system that transports approximately 1.0 MMcf/day of low-sulfur natural gas from the South Elk Basin fields to the Elk Basin natural gas processing plant.

Our Big Horn Basin properties are comprised of assets in Wyoming and the Elk Basin field in south central Montana. We own working interests ranging from 25% to 100% in our Big Horn Basin properties, which consisted of 24,512 gross (15,632 net) leasehold acres as of December 31, 2017. During 2017, our properties in the Big Horn Basin produced approximately 5,446 MMcfe, of which 86% was oil. At December 31, 2017, the Big Horn Basin properties accounted for approximately 83,348 MMcfe or 5% of our total estimated proved reserves at year end, of which 99% were proved developed and 96% were oil, condensate and NGLs.

Anadarko Basin Properties

The Anadarko Basin consists of operated and non-operated properties in the Verden field, and other fields located in the Anadarko Basin of western Oklahoma and the Texas Panhandle. Within the Anadarko Basin, our assets can generally be characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than our other operating areas. Properties in the Anadarko Basin include mature fields with long production histories.

As of December 31, 2017, our Anadarko Basin properties consisted of 99,884 gross (26,752 net) leasehold acres. During 2017, the Anadarko Basin properties produced approximately 2,874 MMcfe, of which 64% was natural gas. At December 31, 2017, these properties accounted for approximately 36,300 MMcfe or 2% of our total estimated proved reserves at year end, of which 99% were proved developed and 66% were natural gas.

Wind River Basin Properties

The Wind River Basin is located in central Wyoming. Our activities are concentrated primarily in the eastern Wind River Basin, along the greater Waltman Arch. Our natural gas production in this basin is gathered through our own gathering systems and delivered to markets through pipelines owned by Tallgrass Interstate Gas Transmission and Colorado Interstate Gas (“CIG”). As of December 31, 2017, our Wind River Basin properties consisted of 87,531 gross (62,465 net) leasehold acres. During 2017, our Wind River Basin properties produced approximately 2,970 MMcfe, of which 86% was natural gas. At December 31, 2017, the properties had total proved reserves of approximately 25,976 MMcfe or 1% of our total estimated proved reserves, of which 100% were proved developed and 88% were natural gas.

Powder River Basin Properties

The Powder River Basin is primarily located in northeastern Wyoming. Our development operations are conducted in our coalbed methane (“CBM”) fields. CBM wells are drilled to 1,500 feet on average, targeting the Big George Coals, typically producing water in a process called dewatering. This process lowers reservoir pressure, allowing the gas to desorb from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a CBM well can range from five to eleven years depending on the coal seam. Our natural gas production in this basin is gathered through gathering and

pipeline systems owned by Powder River Midstream, Fort Union Gas Gathering, LLC and Thunder Creek Gas Services, LLC. As of December 31, 2017, our Powder River Basin properties consisted of 114,287 gross (66,866 net) leasehold acres. During 2017, the properties produced approximately 6,302 MMcfe, which was 100% natural gas. At December 31, 2017, the properties had total proved reserves of approximately 18,015 MMcfe or 1% of our total estimated proved reserves at year end, of which 75% were proved developed and 100% were natural gas.

Oil, Natural Gas and NGLs Prices

We analyze the prices we realize from sales of our oil, natural gas, and NGL production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The West Texas Intermediate Cushing, (“WTI”) price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of crude oil is mainly determined by its quality and location. In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees of API (“American Petroleum Institute”) gravity and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted. Since title of the natural gas sold under these contracts passes at the outlet of the processing plant, we report residue volumes of natural gas in Mcf as production.

The average realized prices described below include deductions for gathering, transportation and processing fees; however, these prices do not include the impact of our hedges.

Production in the Green River Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed natural gas in the Pinedale field is subject to a processing agreement with Western Gas Resources in their Granger Plant facility where we take our residue natural gas in-kind for sales and NGLs are taken in-kind and sold pursuant to a liquids purchase agreement. During 2017, we were able to renegotiate this processing agreement, lowering our fees significantly. We market our Green River Basin residue natural gas into the Rockies market through the use of multiple pipeline connections. During 2017, we received the average NYMEX price less $0.80 per Mcf of natural gas in the Green River Basin. Through our renegotiated processing agreement in the Pinedale field, we are given the opportunity to work directly with the plant to decide whether or not it is best to reject or recover ethane (C2). As of December 31, 2017, we expect to continue ethane rejection in Pinedale through 2018.

Production in the Piceance Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed gas is subject to a processing agreement with Enterprise Gas Processing LLC, in their Meeker Plant facility. We market our natural gas production into the Rockies market at the Northwest Rockies index pricing. During 2017, we received the average NYMEX price less $0.95 per Mcf of natural gas in the Piceance Basin.

In the Permian Basin, most of our natural gas production is casinghead natural gas produced in conjunction with our oil production. Casinghead gas typically has a high Btu content and requires processing prior to sale to third parties. We have a number of processing agreements in place with gatherers/processors of our casinghead natural gas, and we share in the revenues associated with the sale of NGLs resulting from such processing, depending on the terms of the various agreements. For the year ended December 31, 2017, we received the average NYMEX price less $0.94 per Mcf of natural gas in the Permian Basin. Our oil production is sold under month-to-month sales contracts with purchasers that take delivery of the oil volumes at the tank batteries adjacent to the producing wells. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies. During 2017, we received the average NYMEX price less $4.05 per barrel of crude oil in the Permian Basin.

Our Arkoma Basin production in the southeastern Oklahoma Woodford Shale consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third party entities with the processed natural gas ultimately delivered to the Targa Resources, Inc. natural gas processing complex. The processed natural gas is subject to a processing agreement with Targa Resources, Inc., where we take our residue natural gas in-kind for sales, and NGLs are sold pursuant to the terms of the processing agreement. We are contractually provided the ability to make an election to recover or reject ethane (C2) in order to maximize product economics. During 2017, we elected to reject ethane, and expect to continue ethane rejection through 2018. The lean natural gas is primarily delivered

directly to market. The natural gas was marketed at an Enable East index. For the year ended December 31, 2017, we received the average NYMEX price less $1.07 per Mcf of natural gas.

In the Gulf Coast Basin, our natural gas production has a high Btu content and requires processing prior to sale to third parties. Our proportionate share of the natural gas volumes are sold at the tailgate of the processing plant at the Houston Ship Channel and Waha Gas index pricing which typically results in a discount to NYMEX prices. For the year ended December 31, 2017, we received the average NYMEX price less $0.64 per Mcf of natural gas.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections with other pipelines. Our Big Horn Basin sweet crude oil production is transported from the field by a third-party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. During 2017, we received the average NYMEX price less $7.99 per barrel of crude oil in the Big Horn Basin.

In the Williston Basin, we produced a combination of sweet and legacy sour oil. This oil is both connected to oil pipelines as well as trucked out for sales and there is minimal natural gas associated with this production. During 2017, we received the average NYMEX price less $7.18 per barrel of crude oil in the Williston Basin. On December 21, 2017, we divested substantially all of our Williston assets with an effective date of August 1, 2017.

Our Anadarko Basin production in Oklahoma consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third party entities. The lean natural gas is gathered by Enable Gathering & Processing LLC and sold to market at Enable Oklahoma Intrastate Transmission LLC’s West pool at the Panhandle, TX-Okla. index pricing. The high Btu gas is sold at the wellhead to various third party entities. The majority is sold to Oneok Field Services Company LLC and DCP Midstream LP under gas purchase contracts subject to percent of proceeds pricing for all products. During 2017, we received the average NYMEX price less $1.49 per Mcf of natural gas in the Anadarko Basin.

Our Wind River Basin properties are predominantly natural gas plays with approximately two-thirds of the production being processed at natural gas plants for the extraction of NGLs at our election. Our residue natural gas is sold into the Rockies market at the CIG index price while the NGLs are sold to a third-party natural gas processor pursuant to a processing agreement.

Our Powder River natural gas production is classified as CBM gas and, as it is a very dry gas, is sold directly into the market upon being handled with conventional separation, treating, and transportation. In 2017, we were able to renegotiate our current gathering agreement to allow for lower rates, effective December 1, 2017. The CBM gas is sold into the Rockies market at the CIG index price as well. During 2017, we received the average NYMEX price less $0.82 per Mcf of natural gas in the Wind River Basin while we received the average NYMEX price less $1.96 per Mcf of natural gas in the Powder River Basin.

Oil, Natural Gas and NGLs Data

Estimated Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of the estimated proved reserves at December 31, 2017, as estimated by our internal reservoir engineers. The estimate of net proved reserves has not been filed with or included in reports to any federal authority or agency. The Standardized Measure value shown in the table is not intended to represent the current market value of our estimated oil, natural gas and NGLs reserves. Please see “Reserves Estimation Process” below and the “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding our estimated proved reserves.



Reserve Data:
Estimated net proved reserves:
Crude oil (MMBbls)	39.0
Natural gas (Bcf)	1,357.6
NGLs (MMBbls)	38.4
Total (Bcfe)	1,821.5
Proved developed (Bcfe)	1,225.3
Proved undeveloped (Bcfe)	596.2
Proved developed reserves as % of total proved reserves	67		%
PV-10 ⁽¹⁾	$	1,194.8
Less: Future income taxes (discounted at 10%)	(121.2		)
Standardized Measure (in millions) ⁽²⁾	$	1,073.6
Representative Oil and Natural Gas Prices ⁽³⁾:
Oil—WTI per Bbl	$	51.22
Natural gas—Henry Hub per MMBtu	$	2.99
NGLs—Volume-weighted average price per Bbl	$	19.24

(1)

PV-10 is the present value of estimated future net revenues to be generated from the production of proved reserves, calculated net of estimated production costs and future development costs, using prices based on the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”, and without giving effect to non-property related expenses such as selling, general and administrative expenses and debt service, future income tax expense or to depreciation, depletion, amortization, and accretion and discounted using an annual discount rate of 10%. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows.

(2)

Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) (using the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”) and calculated net of the estimated future costs incurred in developing, producing and abandoning the proved reserves. Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Item 1. Business—Operations—Price Risk Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

(3)

Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month average price for January through December 2017, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using differentials to the oil 12-month average price per Bbl of $51.22.

The following tables set forth certain information with respect to our estimated proved reserves by operating basin as of December 31, 2017:



	Estimated Proved Developed Reserve Quantities				Estimated Proved Undeveloped Reserve Quantities				Estimated Proved Reserve Quantities
	Natural Gas (Bcf)	Oil (MMBbls)	NGLs (MMBbls)	Total (Bcfe)	Natural Gas (Bcf)	Oil (MMBbls)	NGLs (MMBbls)	Total (Bcfe)	Total (Bcfe)
Operating Basin
Green River Basin	309.3	2.9	4.9	355.7	343.1	3.5	5.0	394.4	750.1
Piceance Basin	182.7	1.5	14.1	276.2	10.3	0.1	0.9	16.2	292.4
Permian Basin	51.0	10.8	4.5	143.1	0.1	0.1	0.1	1.0	144.1
Arkoma Basin	175.5	0.1	1.9	187.3	150.2	—	—	150.2	337.5
Gulf Coast Basin	49.2	6.0	3.3	105.0	17.3	0.9	1.0	28.8	133.8
Big Horn Basin	3.4	11.6	1.6	82.4	0.3	0.1	—	0.9	83.3
Anadarko Basin	23.9	1.4	0.6	36.1	0.2	—	—	0.2	36.3
Wind River Basin	22.9	0.1	0.4	26.0	—	—	—	—	26.0
Powder River Basin	13.5	—	—	13.5	4.5	—	—	4.5	18.0
Total	831.4	34.4	31.3	1,225.3	526.0	4.7	7.0	596.2	1,821.5



	PV-10 Value ⁽¹⁾
	Developed		Undeveloped		Total
Operating Basin	(in millions)
Green River Basin	$	277.0	$	97.2	$	374.2
Piceance Basin	219.7		2.7		222.4
Permian Basin	163.7		1.0		164.7
Arkoma Basin	115.9		21.5		137.4
Gulf Coast Basin	106.3		14.4		120.7
Big Horn Basin	117.9		1.6		119.5
Anadarko Basin	33.0		0.4		33.4
Wind River Basin	14.6		—		14.6
Powder River Basin	6.7		1.2		7.9
Total	$	1,054.8	$	140.0	$	1,194.8

(1)

The data in the above tables represent estimates only. Oil, natural gas and NGLs reservoir engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future sales prices may differ from those assumed in these estimates. Please read “Item 1A. Risk Factors.”

Our internal reservoir engineers’ estimates of future net revenues from our properties, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions using the unweighted arithmetic average first day of the month prices for the 12-month period ended December 31, 2017 for each product.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The PV-10 and standardized measure disclosed in this Annual Report should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board’s (“FASB”) ASC, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to the timing of future production, which may prove to be inaccurate.

Proved Undeveloped Reserves

During 2017, our proved undeveloped reserves increased by approximately 596.2 Bcfe primarily due to additions of

undeveloped reserves which were classified as contingent resources as of December 31, 2016, due to uncertainty regarding the availability of capital that would be required to develop the PUD reserves prior to the filing of and emergence from bankruptcy.

The PV-10 Value of our proved undeveloped reserves was $140.0 million at December 31, 2017.

We expect to spend approximately 68% of our planned five year future development costs within the next three years as reflected in our reserve report. We did not report any proved undeveloped reserves at December 31, 2016. Consequently, we did not have any proved undeveloped reserves to convert to proved developed reserves during 2017.

Our development plan for drilling proved undeveloped wells includes the drilling of 197 net wells before the end of 2022 at an estimated cost of $524.8 million. This development plan calls for the drilling and completion of 59 net wells during 2018, 41 net wells during 2019, 43 net wells during 2020, 34 net wells during 2021 and 20 net wells during 2022. The expected plan of development of our total proved undeveloped reserves at December 31, 2017, over the next five years is as follows:



	Percent of Proved Undeveloped Reserves Expected to be Converted
2018	25%
2019	22%
2020	21%
2021	19%
2022	13%
Total	100%

At December 31, 2017, none of our proved undeveloped properties are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped. Additionally, none of our proved undeveloped reserves at December 31, 2017 have remained undeveloped for more than five years, as all proved undeveloped reserves are considered 2017 additions.

Our development plan discussed above for drilling proved undeveloped wells represents management’s final investment decision to drill these proved undeveloped reserves at the time the applicable proved undeveloped reserves are booked. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as (i) changes in commodity prices, (ii) anticipated cash flows and projected rate of return, (iii) access to capital, (iv) new opportunities with better returns on investment that were not known at the time of the reserve report, (v) asset acquisitions and/or sales and (vi) actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped reserves that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped reserves development, in favor of projects with a more attractive rate of return, leading us to deviate from our original development plan.

Substantially all of our developed and undeveloped leasehold acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The leases in which we hold an interest that are not held by production are not material to us since these leases have no proved undeveloped reserves assigned.

Reserve Estimation Process

Estimates of proved reserves at December 31, 2017 disclosed in this Annual Report, including proved reserve volumes, PV-10 and the standardized measure of future net cash flows, were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. Our reserve estimation process is a collaborative effort coordinated by our reservoir engineers in compliance with our internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, natural gas and NGLs prices, production costs, future capital expenditures and our net ownership percentages are obtained from other departments within the Company. Our internal reservoir engineers perform review procedures with respect to such non-technical inputs. Reserve variances are discussed among the internal reservoir engineers and the Executive Vice President of Operations.

We use technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, production data, well test data, geologic maps, electrical logs and radioactivity logs. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

Our reservoir engineering group is directly responsible for our reserve evaluation process and consists of eight professionals, four of whom hold, at a minimum, bachelor’s degrees in engineering. Within our Company, our Reservoir Engineering Manager is the technical person primarily responsible for overseeing the preparation of the reserve estimates. Our Reservoir Engineering Manager has over 30 years of experience and graduated from the University of Wisconsin-Milwaukee with a Master of Science Degree in Geology/Geophysics.

The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Independent Audit of Reserves

We engage independent petroleum engineers to audit our reserve estimates. Our internal policies and procedures require the independent engineers to prepare their own estimates of proved reserves for properties comprising at least 80% of our year-end proved reserves. Our board of directors requires that the independent petroleum engineers’ estimate of reserve quantities for the properties audited by the independent petroleum engineers are within 10% of our internal estimate. Once completed, our internally prepared year-end reserve estimates are presented to senior management, including the President and Chief Executive Officer, the Executive Vice President and Chief Financial Officer, and the Executive Vice President of Operations, for approval.

For the year ended December 31, 2017, we engaged Miller and Lents, an independent petroleum engineering firm, to perform reserve audit services. The opinion by Miller and Lents for the year ended December 31, 2017 covered producing areas containing 100% of our proved reserves on a net-equivalent-barrel-of-oil basis. Miller and Lents’ opinion indicates that the estimates of proved reserves related to our oil and natural gas properties prepared by our internal reservoir engineers and reviewed by Miller and Lents, when compared in total on a net-gas-equivalent basis, do not differ materially from the estimates prepared by Miller and Lents. Such estimates by Miller and Lents in the aggregate were within our 10% variation tolerance when compared to those prepared by our reservoir engineering group. The report prepared by Miller and Lents was developed utilizing geological and engineering data we provided. The report of Miller and Lents dated January 31, 2018, which contains further discussion of the reserve estimates and evaluations prepared by Miller and Lents, as well as the qualifications of Miller and Lents’ technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report and incorporated herein by reference.

Within Miller and Lents, the lead technical person primarily responsible for overseeing the audit of our reserves is Ms. Leslie A. Fallon. Ms. Fallon is a Senior Vice President with Miller and Lents and has over 30 years of experience in oil and gas reservoir studies and reserves evaluations. She graduated from the University of Texas at Austin in 1983 with a Bachelor of Science Degree in Mechanical Engineering and is a licensed Professional Engineer in the State of Texas. Ms. Fallon meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

During 2017, we paid fees of approximately $0.4 million to independent petroleum engineers for all reserve and economic evaluations.

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated. Information for fields with greater than 15% of our total proved reserves have been listed separately in the table below for the years ended December 31, 2017, 2016, and 2015, respectively.



	Net Production⁽¹⁾						Average Realized Sales Prices ⁽²⁾							Production Cost ⁽³⁾
	Crude Oil Bbls/day		Natural Gas Mcf/day		NGLs Bbls/day		Crude Oil Per Bbl		Natural Gas Per Mcf		NGLs Per Bbl			Per Mcfe
Year Ended December 31, 2017
Pinedale (Green River Basin)	796		92,038		1,310		$	46.15	$	2.37	$	18.91		$	0.47
Mamm Creek (Piceance Basin)	535		45,704		3,676		$	41.47	$	2.27	$	14.16		$	0.56
All other fields	8,993		119,816		4,108		$	42.57	$	2.22	$	25.06		$	1.60
Total	10,324		257,558		9,094		$	42.38	$	2.28	$	19.77		$	1.08

Year Ended December 31, 2016
Pinedale (Green River Basin)	844		97,323		958		$	59.58	$	3.40	$	(1.72	)	$	0.44
Mamm Creek (Piceance Basin)	579		50,166		3,746		$	52.21	$	2.39	$	11.65		$	0.53
All other fields	11,308		147,885		5,449		$	53.34	$	2.85	$	16.86		$	1.40
Total	12,731		295,374		10,153		$	53.20	$	2.95	$	13.19		$	1.01

Year Ended December 31, 2015
Pinedale (Green River Basin)	804		98,266		1,932		$	58.87	$	2.37	$	0.26		$	0.54
Mamm Creek (Piceance Basin)	649		58,764		3,701		$	49.30	$	1.96	$	12.18		$	0.43
All other fields	9,529		135,066		3,927		$	57.24	$	2.07	$	21.71		$	1.41
Total	10,982	53,695	292,096	84	9,560	45.11	$	56.89	$	3.13	$	13.68		$	0.96


(1)	Average daily production calculated based on 365 days for 2017, 366 days for 2016, and 365 days for 2015, and includes production for all of our acquisitions from the closing dates of the acquisitions.

(2)

Average realized sales prices above include the impact of hedges, allocated proportionately by field, but exclude 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 average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31, 2017 Compared to Year Ended December 31, 2016” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31, 2016 compared to Year Ended December 31, 2015.”


(3)	Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).

Productive Wells

The following table sets forth information at December 31, 2017 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.



	Natural Gas Wells		Oil Wells		Total
	Gross	Net	Gross	Net	Gross	Net
Green River Basin	2,835	411	22	21	2,857	432
Piceance Basin	1,036	922	3	3	1,039	925
Permian Basin	682	373	2,501	731	3,183	1,104
Arkoma Basin	1,431	325	8	2	1,439	327
Gulf Coast Basin	770	281	141	60	911	341
Big Horn Basin	9	5	275	194	284	199
Anadarko Basin	539	72	265	14	804	86
Wind River Basin	136	127	6	6	142	133
Powder River Basin	628	355	—	—	628	355
Total	8,066	2,871	3,221	1,031	11,287	3,902

Developed and Undeveloped Leasehold Acreage

The following table sets forth information as of December 31, 2017 relating to our leasehold acreage.



	Developed Acreage ⁽¹⁾		Undeveloped Acreage ⁽²⁾		Total Acreage
	Gross ⁽³⁾	Net ⁽⁴⁾	Gross ⁽³⁾	Net ⁽⁴⁾	Gross ⁽³⁾	Net ⁽⁴⁾
Green River Basin	60,730	24,837	65,690	10,333	126,420	35,170
Piceance Basin	16,112	10,477	9,208	6,878	25,320	17,355
Permian Basin	315,470	217,364	24,418	15,340	339,888	232,704
Arkoma Basin	373,257	170,927	15,766	8,454	389,023	179,381
Gulf Coast Basin	138,440	56,267	23,114	13,479	161,554	69,746
Big Horn Basin	23,392	14,559	1,120	1,073	24,512	15,632
Anadarko Basin	67,946	18,389	31,938	8,363	99,884	26,752
Wind River Basin	22,989	21,026	64,542	41,439	87,531	62,465
Powder River Basin	65,106	37,868	49,181	28,998	114,287	66,866
Total	1,083,442	571,714	284,977	134,357	1,368,419	706,071


(1)	Developed acres are acres spaced or assigned to productive wells.


(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such leasehold acreage contains proved reserves.


(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.


(4)	A net acre is deemed to exist when the sum of the fractional ownership workings interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Drilling Activity

The following is a description of the Company’s drilling and completion activities during the year ended December 31, 2017.

In the Green River Basin, we participated in the drilling of 170 gross wells (24.2 net) and the completion of 137 gross wells (19.7 net) in Sublette County in southwestern Wyoming. These wells are directionally drilled from pads but are vertical through the 5,000 feet pay section. The average well depth is approximately 14,000 feet and is typically completed with 14 to 20 frac

stages. In addition, we drilled and completed one operated vertical well with 100% working interest in Carbon County, Wyoming. The well was drilled to a vertical depth of approximately 4,000 feet.

In the Permian Basin, we participated in the drilling and completion of two gross vertical wells (0.07 net) in Gaines County, Texas. We also participated in the drilling of five gross (0.06 net) horizontal wells in Eddy County, New Mexico. The vertical wells were drilled to average depths of approximately 7,000 feet to 8,000 feet. The horizontal wells were drilled to vertical depths of 7,000 to 9,000 feet and extended with horizontal lateral lengths of approximately 7,000 to 10,000 feet.

In the Gulf Coast Basin, we drilled six (5.3 net) operated wells and completed four (3.7 net) operated wells in the East Haynesville field in Claiborne County, Louisiana. Three of these wells are directionally drilled from pads but are vertical through the 500 to 1,000 feet pay section. The average well depth is approximately 10,000 feet and is typically completed with 2 to 3 frac stages.

In the Piceance Basin, we drilled five gross (4.98 net) operated wells working interest in Garfield County, Colorado. These wells are directionally drilled from pads but are vertical through the 2,500 feet pay section. The average well depth is approximately 8,000 feet and is typically completed with 8 frac stages.

In the Big Horn Basin, we participated in the drilling and completion of four gross (1 net) wells in Park County, Wyoming. These wells are directionally drilled from pads but are vertical through the 400 feet pay section. The average well depth is approximately 6,500 feet and is typically completed with 2 frac stages. We also drilled one gross (0.60 net) operated well working interest in Carbon County, Montana.

In the Arkoma Basin, we participated in the drilling and completion of three gross (0.07 net) wells in Logan and Cleburne Counties in Arkansas. We also participated in the drilling of seven (0.9 net) horizontal wells in Coal and Pittsburg counties in Oklahoma. These wells were drilled to vertical depths of 7,000 to 10,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet.

In the Anadarko Basin, we participated in the drilling of six gross (0.06 net) horizontal wells and the completion of four gross (0.06 net) horizontal wells in several counties in Oklahoma. These wells were drilled to vertical depths of 8,000 to 13,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 7,000 feet.

The Board approved an initial capital expenditures budget for 2018 of $160.0 million compared to the $109.9 million we spent in 2017. Our initial 2018 capital expenditures budget includes approximately $135.0 million of drilling and completion capital, or 85% of the total capital budget. More than 97% of the drilling and completion capital is focused on the core growth assets of the Green River, Piceance and Arkoma Basins. We expect to spend between $90.0 million to $95.0 million or approximately 69% of the drilling capital budget in the Green River Basin at the Pinedale field where we will participate as a non-operated partner in the drilling and completion of vertical and horizontal natural gas wells. Additionally, we expect to spend between $20.0 million to $26.0 million or approximately 15% of the drilling capital budget in the Piceance Basin, at the Mamm Creek field where we will operate a one rig program drilling and completing vertical gas wells. We also expect to spend approximately 13% of our budgeted drilling capital in the Arkoma Basin in Oklahoma where we will be participating as a non-operated partner with Newfield and BP in a one rig program drilling and completing horizontal Woodford wells. The remaining drilling and completion capital will be spent on additional drilling, completion and production uplift projects in the Permian, Big Horn, and Powder River Basins. The Company intends to release a revised 2018 capital expenditures budget and other guidance with the release of its first quarter results that will include, among other items, the impact of reduced rig counts with increased horizontal development spending in the Pinedale field.

The following table sets forth information with respect to wells completed during the years ended December 31, 2017, 2016 and 2015. Our drilling activity during these periods has consisted entirely of drilling development wells. We have not drilled any exploratory wells during these periods. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil, natural gas, and NGLs regardless of whether they produce a reasonable rate of return.



	Year Ended December 31,
	2017	2016	2015
Gross wells:
Productive	209	137	169
Dry	1	—	—
Total	210	137	169
Net Development wells:
Productive	37.2	15.7	23.6
Dry	1	—	—
Total	38.2	15.7	23.6

Operations

Principal Customers

For the seven months ended July 31, 2017 (Predecessor), sales of oil, natural gas and NGLs to ConocoPhillips, Mieco Inc., Plains Marketing, L.P., Exxon Mobil and XTO Energy accounted for approximately 13%, 11%, 7%, 6% and 3%, respectively, of our oil, natural gas and NGLs revenues and for the five months ended December 31, 2017 (Successor), sales of oil, natural gas and NGLs to ConocoPhillips, Mieco Inc., Plains Marketing, L.P., Exxon Mobil, and Energy Midstream accounted for approximately 14%, 12%, 7%, 7%,and 3%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the seven months ended July 31, 2017 and the five months ended December 31, 2017 therefore accounted for 40% and 43%, respectively, of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash flows from operations could decline. However, if we were to lose a customer, we believe a substitute purchaser could be identified in a timely manner and upon similar terms and conditions.

Delivery Commitments and Marketing Arrangements

Our oil and natural gas production is principally sold to marketers, processors, refiners, and other purchasers that have access to nearby pipeline, processing and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally are month-to-month or have terms of one year or less.

We generally sell our natural gas production from our operated properties on the spot market or under market-sensitive, short-term agreements with credit-worthy purchasers, including independent marketing companies, gas processing companies, and other purchasers who have the ability to pay the highest price for the natural gas production and move the natural gas under the most efficient and effective transportation agreements. Because all of our natural gas production from our operated properties is sold under market-priced agreements, we are positioned to take advantage of future increases in natural gas prices but we are also subject to any future price declines. We do market our own natural gas on some of our non-operated properties.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other export pipelines. Our Big Horn Basin sweet crude oil production is transported from the field by a third party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. We sell oil production from our operated Permian Basin properties at the wellhead to third-party gathering and marketing companies.

Our natural gas is transported through our own and third-party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party gatherer, processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we may enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. Currently, a majority of our existing firm transportation agreements were assumed in connection with acquisitions of oil and natural gas properties. These agreements

have term delivery commitments of fixed and determinable quantities of natural gas. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contractual Obligations” for additional information regarding our long-term firm transportation contracts.

The following table sets forth information about material long-term firm transportation contracts for pipeline capacity, which typically require a demand charge. We source the gas to meet these commitments from our producing properties. We have certain commitments that we assumed as part of our acquisitions of oil and gas properties where the production from the acquired properties and the production of joint interest owners that we market were not adequate to meet the commitments resulting in us paying the set demand charge relating to the maximum daily quantity outlined in the contract. During the year ending December 31, 2018, our firm transportation contracts obligate us to deliver 30,000 MMBtu of natural gas per day.



Type of Arrangement	Pipeline System /Location	Deliverable Market	Gross Deliveries (MMBtu/d)	Term
Firm Transport	WIC Medicine Bow	Rocky Mountains	25,000	01/18 – 06/20
Firm Transport	Cheyenne Plains	Midcontinent	5,000	01/18 – 05/18

Price Risk Management Activities

We routinely enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil, natural gas and NGLs price volatility on our cash flow from operations. Currently, we primarily use fixed-price swaps and other hedge option contracts to hedge oil and natural gas prices. By removing the price volatility from a significant portion of our oil and natural gas production, we are able to mitigate for a period of time, but not eliminate, the potential effects of fluctuation in oil and natural gas prices on our cash flow from operations. For a description of our derivative positions, please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staff substantially larger than ours or a different business model. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for, purchase, or develop a greater number of properties or prospects than our financial, technical or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure stockholders that we will be able to compete satisfactorily when attempting to make future acquisitions.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, however, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our oil and natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests, contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for taxes not yet payable and other burdens, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of

these properties or from our interest in these properties, or will materially interfere with our use of these properties in the operation of our business.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in the Gulf Coast Basin, Piceance Basin, Big Horn Basin, and the Potato Hills Pipeline. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:


•	realize faster connection of newly drilled wells to the existing system;


•	control pipeline operating pressures and capacity to maximize production;


•	control compression costs and fuel use;


•	maintain system integrity;


•	control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and


•	track sales volumes and receipts closely to assure all production values are realized.

Seasonal Nature of Business

Seasonal weather conditions, severe weather events, and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increased costs or delay our operations. Generally, but not always, oil is typically in higher demand in the late summer due to the summer driving season, which results in increased gasoline and diesel usage and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as hot summers or mild winters, which are unpredictable, sometimes impact this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental and Occupational Health and Safety Matters

General. Our business involving the acquisition and development of oil and natural gas properties is subject to extensive and stringent federal, state and local laws and regulations governing the discharge of materials into the environment, environmental protection, and the health and safety of employees. Our operations are subject to the same environmental, health and safety laws and regulations as other similarly situated companies in the oil and natural gas industry. These laws and regulations may:


•	require the acquisition of permits before commencing drilling or other regulated activities;


•	require the installation of expensive pollution control equipment and performance of costly remedial measures to mitigate or prevent pollution from historical and ongoing operations, such as pit closure and plugging of abandoned wells;


•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;


•	limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;


•	impose specific health and safety criteria addressing worker protection;


•	impose substantial liabilities for pollution resulting from operations; and


•	require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement for operations affecting federal lands or leases.

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, imposition of removal or remedial obligations, and the issuance of orders enjoining some or all of our operations deemed in non-compliance. Moreover, these laws and regulations may restrict our ability to produce oil, natural gas and NGLs by, among other things, limiting production from our wells, limiting the number of wells we are allowed to drill or limiting the locations at which we may conduct our drilling operations. The regulatory burden on the oil and natural gas

industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly well drilling, construction, completion and water management activities, or waste handling, disposal and clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs. We believe that operation of our wells is in substantial compliance with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot provide any assurance that we will not incur substantial costs in the future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition, and results of operations. For the year ended December 31, 2017, we did not incur any material capital expenditures for performance of remediation or installation of pollution control equipment at any of our facilities; however, we did incur capital expenditures in the ordinary course of business to comply with pollution control requirements. As of the date of this Annual Report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2018 or that will otherwise have a material adverse impact on our financial position or results of operations.

The following is a summary of the more significant existing environmental and occupational health and safety laws to which our business operations are subject and for which compliance may have a material adverse impact on our operations as well as the oil and natural gas exploration and production industry in general.

Waste Handling. The Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state laws, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” as well as the disposal of non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or the “EPA,” individual states administer some or all of the federal provisions of RCRA, sometimes in conjunction with their own, more stringent state requirements. Drilling fluids, produced waters, and many other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy are currently regulated under RCRA’s less stringent non-hazardous waste provisions. However, by amendment of existing RCRA laws and regulations, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could increase our costs to manage and dispose of such generated wastes, which cost increase could be significant. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as RCRA hazardous wastes.

Hazardous Substance Releases. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA,” or “Superfund,” and analogous state laws, impose joint and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that transported or disposed or arranged for the transportation or disposal of the hazardous substance found at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While materials are generated in the course of operation of our wells that may be regulated as hazardous substances, we have not received any pending notifications that we may be potentially responsible for cleanup costs under CERCLA.

We currently own, lease, or have a non-operating interest in numerous properties that have been used for oil and natural gas production for many years. Although we believe that operating and waste disposal practices used on these properties in the past were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where these substances, wastes and hydrocarbons have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

As of December 31, 2017, we have recorded $4.2 million for future remedial costs and abandonment liability for decommissioning the Big Escambia Creek, Elk Basin, and Fairway natural gas processing plants.


•	Our Elk Basin assets include a natural gas processing plant. Previous environmental investigations identified historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected

historical hydrocarbon contamination or abatement of the asbestos, the extent of the hydrocarbon contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event we cease operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. We do not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require us to investigate and remediate any hydrocarbon contamination even while the gas plant remains in operation.


•	In addition, we own and operate the Fairway natural gas processing plant in the Gulf Coast Basin, for which we have reserved abandonment costs.

•

We continue to operate a groundwater remediation project at our Big Escambia Creek gas plant. This release occurred when a prior owner operated the Big Escambia Creek gas plant. We operate our pump and treat system to treat groundwater under the supervision of the Alabama Department of Environmental Management. We conducted repairs on the existing system in 2017 to help reduce the downtimes and increase rates of water volume treated.

Our estimates of the future remediation cost are subject to change, and the actual cost of these items could vary significantly from the above estimates. Due to the significant uncertainty associated with the known environmental liabilities at the gas plants, our estimate of the future abandonment liability includes a reserve.

Pipeline Safety. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, state agencies, the courts, or Congress may make determinations that affect PHMSA’s regulations or their applicability to the Company’s pipelines. These determinations may affect the costs the Company incurs in complying with applicable safety regulations.

Water Discharges. The Federal Water Pollution Control Act, as amended, or “Clean Water Act,” and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into state waters as well as waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by U.S. EPA or the relevant state with delegated authority. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure, or “SPCC,” requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by an oil spill or release. If an oil spill or release were to occur as a result of our operations, we expect that it would be contained and remediated in accordance with our SPCC plan together with the assistance of trained first responders and any oil spill response contractor that we may have engaged to address such spills and releases. The Clean Water Act and analogous state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

Fluids associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in below ground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control, or UIC, program established under the federal Safe Drinking Water Act, or SDWA, and analogous state laws. The UIC program requires permits from U.S. EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While we believe that our disposal well operations substantially comply with requirements under the UIC program, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into below ground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission, or TRC, published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.

The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including

exploration and production facilities that are the site of a release of oil into waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. We believe we are in substantial compliance with the Clean Water Act, OPA and analogous state laws.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years. From time to time Congress has considered adopting legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Federal agencies have asserted regulatory authority over certain aspects of the process. For example, U.S. EPA has taken several steps to federalize regulation of hydraulic fracturing. It issued Clean Air Act rules governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, the effective date of which has recently been delayed. In June 2016, U.S. EPA issued final rules establishing effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant. U.S. EPA also considered a rule under its Toxic Substances Control Act authority requiring reporting of the chemical substances and mixtures used in hydraulic fracturing, though U.S. EPA has not followed through on its initial consideration of such a rule. As a final example of federalization of regulation of hydraulic fracturing, on March 26, 2015, BLM issued a rule requiring chemical disclosure and other mandates for hydraulic fracturing on federal lands, which BLM has since proposed rescinding.

Some states in which the Company operates, including Montana, Texas and Wyoming, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability and control of well insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Air Emissions. The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and their implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with air permit requirements containing various emissions and operational limitations, or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. To date, we believe that no significant difficulties have been encountered in obtaining air permits. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air control equipment in connection with obtaining and maintaining operating permits and approvals for emissions of pollutants. For example, in October 2015, U.S. EPA issued a final rule that strengthened the National Ambient Air Quality Standard, or “NAAQS,” for ozone from 75 parts per billion, or “ppb,” to 70 ppb for both the 8-hour primary and secondary standards. On November 7, 2017, U.S. EPA began releasing its revision of attainment and non-attainment air quality control regions based on the new ozone standard. If regions reclassified as non-attainment under the lower ozone standard begin implementing new, more stringent regulations, those regulations could apply to our or our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Activities on Federal Lands. Oil and natural gas exploitation and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Our current production activities, as well as proposed development plans, on federal lands require governmental permits or similar authorizations that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Climate Change. In response to findings made by U.S. EPA that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes, U.S. EPA has adopted regulations under existing provisions of the Clean Air Act that establish Title V operation and Prevention of Significant Deterioration, or “PSD,” construction permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which typically will be established by the states. These U.S. EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, U.S. EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities in the United States on an annual basis, which include certain of our operations. We are conducting monitoring of GHG emissions from our operations in accordance with the GHG emissions reporting rule and we believe that our monitoring and reporting activities are in substantial compliance with applicable reporting obligations.

While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. For example, on June 3, 2016, U.S. EPA published a Methane Rule aimed at reducing methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. The Methane Rule requires oil and gas companies to find and repair leaks, capture gas from completion of fracked wells, limit emissions from new and modified pneumatic pumps, limit emissions from several types of equipment used at gas transmission compressor stations, including compressors and pneumatic controllers, and requires “green completions” to capture natural gas from most new fractured wells. On June 16, 2017, U.S. EPA proposed to delay the Methane Rule’s effectiveness for two years from the final rule’s publication.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

Endangered Species Act Considerations. Various federal and state statutes prohibit certain actions that adversely affect endangered and their habitats, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act, and the Clean Water Act. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service, or “FWS,” is required to make a determination on listing of numerous species as endangered or threatened under the ESA through the agency’s 2018 fiscal year.

If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. If we were to cause harm to species or damages to wetlands, habitat or natural resources as a result of our operations, government entities or, at times, private parties could seek to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, the government could seek criminal penalties. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

While some of our facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, we believe our operations are in substantial compliance with the ESA. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, Colorado and Oklahoma, where we conduct operations, as a threatened species under the ESA. The FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, or WAFWA, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. We have been a party to a Conservation Easement governing nearly 50,000 of affected acreage pursuant to which we agree to adopt certain adaptive management principles and pay an acreage-based mitigation assessment. Calendar year 2017 is the final year during which we expect to pay such assessment.

Occupational Safety and Health. We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, U.S. EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules, orders and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. For example, on July 1, 2014, the North Dakota Industrial Commission adopted Order No. 24665, or the “July 2014 Order,” pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of natural gas produced in the State by October 1, 2014, 77% percent of such gas by January 1, 2015, 85% of such gas by January 1, 2016 and 90% of such gas by October 1, 2020. The July 2014 Order establishes an enforcement mechanism for policy recommendations that were previously adopted by the North Dakota Industrial Commission in March 2014. Those recommendations required all exploration and production operators applying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s now-implemented gas capture percentage goals. In particular, the July 2014 Order provides that after an initial 90-day period, wells must meet or exceed the North Dakota Industrial Commission’s gas capture percentage goals on a per-well, per-field, county, or statewide basis. Failure to comply with the gas capture percentage goals will result in an operator having to restrict its production to 200 barrels of oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or 100 barrels of oil per day if less than 60% of such monthly volume of natural gas is captured. While we believe that we were in compliance with these requirements as of December 31, 2017 and expect to remain in compliance in the future, there is no assurance that we will be able to remain in compliance in the future or that such future compliance will not have a material adverse effect on our business and operational results. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:


•	the location of wells;


•	the method of drilling and casing wells;


•	the surface use and restoration of properties upon which wells are drilled;


•	the plugging and abandoning of wells; and


•	notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil, natural gas and NGLs we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Regulation of Transportation and Sales. The availability, terms and cost of transportation significantly affect sales of oil, natural gas and NGLs. The interstate transportation of natural gas is subject to federal regulation primarily by the Federal Energy Regulatory Commission, or “FERC,” under the Natural Gas Act of 1938, or “NGA.” FERC regulates interstate natural gas pipeline transportation rates and service conditions, which may affect the marketing and sales of natural gas. FERC requires interstate pipelines to offer available firm transportation capacity on an open-access, non-discriminatory basis to all natural gas shippers. FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. State laws and regulations generally govern the gathering and intrastate transportation of natural gas. Natural gas gathering systems in the states in which we operate are generally required to offer services on a non-discriminatory basis and are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.

The ability to transport oil and NGLs is generally dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act, or subject to regulation by the particular state in which such transportation takes place. Laws and regulation applicable to pipeline transportation of oil largely require pipelines to charge just and reasonable rates published in agency-approved tariffs and require pipelines to provide non-discriminatory access and terms and conditions of service. The justness and reasonableness of interstate oil and natural gas liquid pipeline rates can be challenged at FERC through a protest or a complaint and, if such a protest or complaint results in a lower rate than that on file, pipeline shippers may be eligible to receive refunds or, in the case of a complaining shipper, reparations for the two-year period prior to the filing of the complaint. Certain regulations imposed by FERC, by the United States Department of Transportation and by other regulatory authorities on pipeline transporters in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

Under the Energy Policy Act of 2005, or “EPAct 2005,” Congress made it unlawful for any entity, as defined in the EPAct 2005, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services regulated by the FERC that violates the FERC’s rules. FERC’s rules implementing EPAct 2005 make it unlawful for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act up to $1,000,000 per day per violation. Pursuant to authority granted to FERC by EPAct 2005, FERC has also put in place additional regulations intended to prevent market manipulation and to promote price transparency. For example, FERC has imposed new rules discussed below requiring wholesale purchasers and sellers of natural gas to report to FERC certain aggregated volume and other purchase and sales data for the previous calendar year. While EPAct 2005 reflects a significant expansion of the FERC’s enforcement authority, we do not anticipate that we will be affected by EPAct 2005 any differently than energy industry participants.

In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report on Form No. 552, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Pursuant to Order 704, we may be required to annually report to FERC, starting May 1 of each year, information regarding natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year. In recent years, FERC has also issued rules prohibiting anticompetitive behavior by multiple affiliates of the same entity in the natural gas capacity release

market, issued a policy statement providing natural gas pipelines a cost-recovery mechanism to recoup capital expenditures made to modernize pipeline infrastructure, and issued a rule adopting reforms to its scheduling rules to improve coordination between the natural gas and electric markets.

On August 6, 2009, the Federal Trade Commission, or “FTC,” issued a Final Rule prohibiting manipulative and deceptive conduct in the wholesale petroleum markets. The Final Rule applies to transactions in crude oil, gasoline, and petroleum distillates. The FTC promulgated the Final Rule pursuant to Section 811 of the Energy Independence and Security Act of 2007, or “EISA,” which makes it unlawful for anyone, in connection with the wholesale purchase or sale of crude oil, gasoline or petroleum distillates, to use any “manipulative or deceptive device or contrivance, in contravention of such rules and regulations as the Federal Trade Commission may prescribe.” The Final Rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale, from: (a) knowingly engaging in any act, practice, or course of business – including making any untrue statement of material fact that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.

The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. Sales of condensate and NGLs are not currently regulated and are made at market prices. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or “CFTC.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Although natural gas and oil prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGLs, including imposing severance and other production-related taxes and requirements for obtaining drilling permits. Reduced rates or credits may apply to certain types of wells and production methods.

States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not currently regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGLs that may be produced from our wells, to increase our cost of production, to limit the number of wells or locations we can drill and to limit the availability of pipeline capacity to bring our products to market.

In addition to production taxes, Texas, Oklahoma and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming, Colorado and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment.

The petroleum industry participants are also subject to compliance with various other federal, state and local regulations and laws. Some of these regulations and those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these regulations and laws will have a material adverse effect upon the unitholders.

Federal, State or Native American Leases. Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the BLM and other agencies.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. VNR carries business interruption insurance for the Big Escambia Creek, Flomaton, Fairway James, Elk Basin and XTO Cotton Valley processing facilities. VNR also carries contingent business interruption coverage to protect against upstream shut-ins of our Pinedale, Piceance, Permian, Haynesville, and Wind River productions. We insure any cumulative value of owned property over a certain threshold, and carry control of well and pollution coverage for all VNR wells (including new drills and workovers), and re-drill coverage for those that are economically viable. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

Employees

As of March 16, 2018, we had 348 full-time employees. We also contract for the services of independent consultants involved in land, regulatory, tax, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by collective bargaining agreements. We believe that our relations with our employees are satisfactory.

Offices

Our principal executive office is located at 5847 San Felipe, Suite 3000, Houston, Texas 77057. Our main telephone number is (832) 327-2255.

Available Information

Our website address is www.vnrenergy.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report. We make available on our website under “Investor Center-SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.

You may also find information related to our corporate governance, board committees and company code of business conduct and ethics on our website under “Investor Center-Corporate Governance.” Among the information you can find there is the following:

• Audit Committee Charter;

• Compensation Committee Charter;


•	Health, Safety, and Environmental Committee Charter;

• Nominating and Corporate Governance Committee Charter;


•	Strategic Opportunities Committee Charter;

• Code of Business Conduct and Ethics; and

• Corporate Governance Guidelines.

ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Risks Related to our Business

We emerged from bankruptcy on August 1, 2017, which may adversely affect our business and relationships.

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


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


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


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


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


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

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

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

We may be subject to risks in connection with divestitures.

In November 2017, we announced that we had engaged Jefferies LLC to advise us on strategic alternatives, including reducing financial leverage, expanding access to capital, divesting certain non-core assets, focusing the asset base, and funding growth opportunities. In 2017, we completed divestitures of a portion of our non-core assets as discussed in Note 5 to the Notes to the Consolidated Financial Statements in Part II, Item 8, including the Williston Divestiture (as defined therein) in December 2017. Various factors could materially affect our ability to execute on these strategic alternatives and any contemplated asset divestitures, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.

Our business plan was prepared using certain assumptions, including with respect to our ability to make certain divestitures and asset dispositions. If the level of divestitures actually completed is less than planned or expected, it may not be satisfactory to us or sufficient for our purposes or requirements.

In addition, sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Our actual financial results after emergence from bankruptcy are not comparable to our historical financial information as a result of the implementation of the Final Plan and the transactions contemplated thereby as well as significant updates to our accounting policies.

We have made several significant updates to our accounting policies following emergence:

•

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


•	We changed our method of accounting for natural gas and oil properties from the full cost method to the successful efforts method. We recorded significant impairments of our natural gas and oil properties under the full cost method, which might not have been required under the successful efforts method;


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


•	We changed from a pass-through entity for tax purposes to a C Corporation and, accordingly, a taxable entity.

Accordingly, our financial results following emergence from bankruptcy are not comparable to our historical financial information.

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

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

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

Pursuant to the Final Plan, the composition of our Board changed significantly, and the composition has changed since emergence, with two directors resigning and three being appointed. Currently, our Board consists of seven directors, none of whom previously served on the Board of Directors of our Predecessor. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Predecessor’s Board of Directors and, thus, may have different views on the issues that will determine our future. There is no guarantee that our new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and our plans may differ materially from those of the past.

Oil, natural gas and NGLs prices are volatile due to factors beyond our control and have declined from historical highs. Sustained lower prices or a significant decline in prices of oil, natural gas and NGLs, could have a material adverse impact on us.

Our financial condition, profitability and future growth and the carrying value of our oil and natural gas properties depend substantially on prevailing oil, natural gas and NGLs prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

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 West Texas Intermediate (“WTI”) crude oil spot price per barrel during the years ended December 31, 2016 and 2017 ranged from a low of $26.19 to a high of $60.46 and the Henry Hub natural gas spot price per MMBtu during the same period ranged from a low of $1.49 to a high of $3.80. NGLs prices also demonstrated similar volatility. This price volatility impacted our operating results for the years ended December 31, 2015, 2016 and 2017 and contributed to a reduction in capital expenditures for these years. As of March 12, 2018, the WTI crude oil price per barrel was $61.35 and the Henry Hub natural gas spot price per MMBtu was $2.78.

The prices for oil, natural gas and NGLs are volatile due to a variety of factors, including, but not limited to:

•the domestic and foreign supply of oil and natural gas;


•	the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon production levels which has an impact on oil prices;


•	social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;

•the level and growth of consumer product demand;

•labor unrest in oil and natural gas producing regions;


•	weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

•the price and availability of alternative fuels and renewable energy sources;


•	the impact of the U.S. dollar exchange rates on commodity prices;

•the price of foreign imports;


•	technological advances affecting energy consumption;

•worldwide economic conditions; and

•the availability of liquid natural gas imports and exports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil, natural gas and NGLs.

Sustained lower prices or a significant decline in prices of oil, natural gas and NGLs prices would not only reduce our revenue, but 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 gas properties, all of which could have a material adverse effect on our financial condition, results of operations and reserves. In addition, lower commodity prices may result in additional asset impairment charges from reductions in the carrying values of the Company’s oil and gas properties. During the five months ended December 31, 2017, we recorded impairment charges of $47.6 million on our proved properties. See Note 1 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for additional information.

If the oil and gas industry were to experience a period of declining or sustained low prices in the future, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can affect the value of our shares. Also, declining commodity prices in the future could trigger additional impairment charges to our oil and gas assets or other investments.

Unless we replace our reserves, our existing reserves and production will decline, which would adversely affect our cash flow from operations.

Producing oil and natural gas wells extract hydrocarbons from underground structures referred to as reservoirs. Reservoirs contain a finite volume of hydrocarbon reserves referred to as reserves in place. Based on prevailing prices and production technologies, only a fraction of reserves in place can be recovered from a given reservoir. The volume of the reserves in place that is recoverable from a particular reservoir is reduced as production from that well continues. The reduction is referred to as depletion. Ultimately, the economically recoverable reserves from a particular well will deplete entirely, and the producing well will cease to produce and will be plugged and abandoned. In that event, we must replace our reserves. Unless we are able over the long-term to replace the reserves that are depleted through production, our cash flows from operations, financial condition and results of operations may be adversely affected. In addition, our ability to make necessary capital expenditures to maintain or expand our asset base of oil and natural gas reserves may be adversely affected to the extent of a reduction in our cash flow from operations or the unavailability of financing sources.

We may not be able to obtain funding under the Successor Credit Facility because of a decrease in our borrowing base, or obtain new financing, which could adversely affect our operations and financial condition.

Historically, the Predecessor relied on borrowings under the Predecessor Credit Facility to meet a portion of its capital needs. Pursuant to the Final Plan, the Predecessor Credit Facility was paid down in part and replaced by the Successor Credit Facility entered into in connection with the reorganization, which consists of the Revolving Loans. The initial borrowing base available under the Successor Credit Facility as of the Effective Date was $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date was $730.0 million. The Successor Credit Facility also includes the Term Loan. The next borrowing base redetermination is scheduled for August 1, 2018. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the Successor Credit Facility exceeding the borrowing base, we will be required to repay the deficiency. We may not have the financial resources in the future to make any mandatory deficiency principal prepayments required under the Successor Credit Facility, which could result in an event of default.

In the future, we may not be able to access adequate funding under the Successor Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Since the process for determining the borrowing base under the Successor Credit Facility involves evaluating the estimated value of some of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used, asset divestments, or further downward reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination. In such case, we would be required to repay any indebtedness in excess of the borrowing base.

Our Successor Credit Facility also restricts our ability to incur additional indebtedness. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If net cash provided by operating activities or cash available under our Successor Credit Facility is not sufficient to meet our capital requirements, the failure to obtain such additional debt or equity financing could result in a curtailment of our development operations, which in turn could lead to a decline in our production, reserves, and the PV-10 value of our reserves.

We may be unable to maintain compliance with the financial maintenance or other covenants in the Successor Credit Facility or with the covenants under the New Notes, which could result in an event of default under the Successor Credit Facility or the indenture governing the New Notes that, if not cured or waived, would have a material adverse effect on our business and financial condition.

The Successor Credit Facility contains certain financial covenants, including the maintenance of (i) the ratio of consolidated first lien debt of VNR, VNG, and the subsidiaries as of the date of any determination to EBITDA, as defined under the Successor Credit Facility, for the most recently ended four consecutive fiscal quarter period for which financial statements are available of not more than (a) 4.75 to 1.00 as of the last day 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 PV-9 based on strip pricing of proved reserves plus the impact of hedges, to first lien debt, of not less than 1.25 to 1.00 as tested on each January 1 and July 1 prior to the first scheduled borrowing base date, which takes place on August 1, 2018; and (iii) a ratio, determined as of the last day of each fiscal quarter beginning with the fiscal quarter ending December 31, 2017, of current assets to current liabilities of VNR and its subsidiaries on a consolidated basis of not less than 1.0 to 1.0.

The Successor Credit Facility and the indenture governing the New Notes also contain certain other affirmative and negative covenants. If we were to violate any of the covenants under the Successor Credit Facility or the indenture governing the New Notes, and were unable to obtain a waiver or amendment, it would be considered an event of default. If we were in default under the Successor Credit Facility or the indenture governing the New Notes, then the lenders or the noteholders, as applicable, may exercise certain remedies including, among others, declaring all outstanding indebtedness under the relevant instrument immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due.

Restrictive covenants in the Successor Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Restrictive covenants in the Successor Credit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:


•	incur additional indebtedness;


•	incur additional liens;


•	pay dividends or make other distributions or repurchase or redeem our stock;


•	prepay, redeem, or repurchase certain of our indebtedness


•	make certain investments;


•	enter into certain transactions with our affiliates;


•	make certain capital expenditures;


•	consolidate, merge, sell, or otherwise dispose of certain of our assets;


•	enter into certain marketing activities for hydrocarbons;


•	create additional subsidiaries; and


•	amend or modify certain provisions of our organizational documents.

The Successor Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above.

The indenture governing the New Notes also contains restrictive covenants imposing operating and financial restrictions on us and our subsidiaries, including limiting our ability to, among other things:

•incur, assume or guarantee additional indebtedness or issue preferred stock;

•create liens to secure indebtedness;


•	make distributions on, purchase or redeem the Company’s common stock or purchase or redeem subordinated indebtedness;

•make investments;

•restrict dividends, loans or other asset transfers from the Company’s restricted subsidiaries;

•consolidate with or merge with or into, or sell substantially all of our properties to, another person;

•sell or otherwise dispose of assets, including equity interests in subsidiaries;

•enter into transactions with affiliates; or

•create unrestricted subsidiaries.

A breach of any of these covenants could result in a default under the relevant debt instrument. If a default occurs and remains uncured or unwaived, the administrative agent, the trustee, the majority lenders under the Successor Credit Facility or the holders of more than 25% of the New Notes may elect to declare all outstanding indebtedness under the relevant instrument, together with accrued interest and other fees, if applicable, to be immediately due and payable.

In addition, in the event of such defaults under the Successor Credit Facility, the administrative agent or majority lenders under the Successor Credit Facility would also have the right in these circumstances to terminate any commitments they have to

provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it that secures the indebtedness under the Successor Credit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in the Successor Credit Facility and the indenture governing the New Notes. These restrictions could:


•	limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise restrict our activities or business plan; and


•	adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Disruptions in the capital and credit markets, low commodity prices relative to historical averages and other factors may restrict our ability to raise capital on favorable terms, or at all.

Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Low commodity prices relative to historical averages, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy, and in certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business and financial condition.

A widening of commodity differentials and our inability to enter into hedge contracts for a sufficient amount of our production at favorable pricing could materially adversely impact our financial condition, results of operations and cash flows from operations.

Our crude oil, natural gas and NGLs are priced in the local markets where the production occurs based on local or regional supply and demand factors. The prices that we receive for our crude oil, natural gas and NGLs production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We may not be able to accurately predict crude oil, natural gas and NGLs differentials.

Price differentials may widen in the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, changes in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be adversely impacted by a widening differential on the products we sell. Our oil and natural gas hedges are based on NYMEX index prices and the NGLs hedges are based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices, so we may be subject to basis risk if the differential on the products we sell widens from those benchmarks and we do not have a contract tied to those benchmarks. In the past, we have entered into fixed-price swaps derivative contracts to cover a portion of our NGLs production to reduce exposure to fluctuations in NGLs prices. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive and our inability to enter into hedge contracts at favorable pricing and for a sufficient amount of our production could adversely affect our financial condition, results of operations and cash flows from operations in the future.

Adverse developments in our operating areas would have a negative impact on our results of operations.

Our properties are located in Wyoming, Colorado, Texas, New Mexico, Louisiana, Mississippi, Montana, Arkansas, Oklahoma, and Alabama. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could have a negative impact on our results of operations.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. As of December 31, 2017, our operated wells accounted for approximately 43% of our total estimated proved reserves and wells operated by others accounted for the remaining 57% of our total estimated proved reserves. We have limited ability to influence or control the operation or future development of these non-operated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. In the past, we have changed our development plans for certain proved undeveloped reserves and expect

future development plans may also change as the operators of our outside operated properties adjust their capital plans based on prevailing market conditions. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reservoir engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. We prepare our own estimates of proved reserves and engage Miller and Lents, an independent petroleum engineering firm, to audit 100% of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, the calculation of estimated reserves requires certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs, any of which assumptions may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows.

For example, to illustrate the impact of a volatile 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 December 31, 2017 would decrease from 1,821.5 Bcfe to 1,191.8 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices were $2.84 per MMBtu (or a $0.15 price decrease from the 12-month average price of $2.99) and oil prices were $53.86 per barrel (or a $2.64 price increase from the 12-month average price of $51.22), 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 December 31, 2017 would decrease from 1,821.5 Bcfe to 1,808.0 Bcfe. The preceding assumed prices in example (2) were derived from the 5-year New York Mercantile Exchange (NYMEX) forward strip price at March 12, 2018. Our PV-10 is calculated using prices based on the 12-month average price, as defined by the SEC, and does not give effect to derivative transactions. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.

The PV-10 of our proved reserves at December 31, 2017 may not be the same as the current market value of our estimated oil, natural gas and NGLs reserves.

You should not assume that the present value of future net reserves (“PV-10”) value of our proved reserves as of December 31, 2017 is the current market value of our estimated oil, natural gas and NGLs reserves. We base the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:


•	the actual prices we receive for oil, natural gas and NGLs;


•	our actual development and production expenditures;


•	the amount and timing of actual production; and


•	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry

in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report, which could have a material effect on the value of our reserves. The oil and natural gas prices used in computing our PV-10 and standardized measure of future cash flows as of December 31, 2017 under SEC guidelines were $51.22 per barrel of crude oil and $2.99 per MMBtu for natural gas, respectively, before price differentials.

Using more recent prices in estimating proved reserves would result in a reduction in proved reserve volumes because they are lower than the prices used in estimated proved reserves and due to economic limits, which would further reduce the PV-10 value of our proved reserves.

Our operations require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to sustain our operations at current levels and could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We have made and ultimately expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGLs reserves. We intend to finance our future capital expenditures with cash flow from operations, our financing arrangements and asset sales. Our cash flow from operations and our access to capital are subject to a number of variables, including, but not limited to:


•	our proved reserves;


•	the level of oil, natural gas and NGLs we are able to produce from existing wells;


•	the prices at which our oil, natural gas and NGLs are sold;


•	our ability to consummate planned asset divestitures;


•	the level of operating expenses; and


•	our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to replace or add to our reserves.

Our business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and NGLs we produce and could reduce our revenues.

The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the interest under the property.

We depend on certain key customers for sales of our oil, natural gas and NGLs. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs they purchase from us, or to the extent these customers cease to be creditworthy, our revenues and cash flows from operations could decline.

For the seven months ended July 31, 2017, sales of oil, natural gas and NGLs to ConocoPhillips, Mieco Inc., Plains Marketing, L.P., Exxon Mobil and XTO Energy accounted for approximately 13%, 11%, 7%, 6%, and 3%, respectively, of our oil, natural gas and NGLs revenues, and for the five months ended December 31, 2017, sales of oil, natural gas and NGLs to ConocoPhillips, Mieco Inc., Plains Marketing, L.P., Exxon Mobil, and Energy Midstream accounted for approximately 14%, 12%, 7%, 7%, and 3%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the seven months ended July 31, 2017 and the five months ended December 31, 2017 therefore accounted for 40% and 43%, respectively, of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash flows from operations could decline.

We are, and may be from time to time, subject to litigation, including litigation arising from the LRE Merger, which could have an adverse effect on our financial condition, results of operations, and cash flow.

We are a party to various claims and routine litigation arising in the ordinary course of business. Some of these claims, including claims arising specifically from the LRE Merger (as defined below), or others to which we may be subject from time to time, may result in defense costs, settlements, fines or judgments against us, some of which are not, or cannot be, covered by insurance. Payment of any such costs, settlements, fines or judgments that are not insured could have an adverse impact on our financial position, results of operations, or cash flow. Should we decide to settle for an amount in excess of our insurance coverage or proceed to trial and receive an unfavorable verdict in connection with the LRE Merger, it could adversely impact our financial position, results of operations or cash flow, expose us to increased risks that would be uninsured, and/or adversely impact our ability to attract officers and directors.

Our sales of oil, natural gas and NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.

The FTC, FERC and CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas and NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

We are subject to FERC requirements related to our use of capacity on natural gas pipelines that are subject to FERC regulation. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.

Laws and regulations pertaining to threatened and endangered species could delay or restrict our operations and cause us to incur substantial costs.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, and the Clean Water Act. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in

September 2011, the FWS is required to make a determination on listing of numerous species as endangered or threatened under the ESA through the agency’s 2018 fiscal year.

Please read “Operations-Environmental and Occupational Health Safety Matters-Endangered Species Act Considerations” included under Part I, Item 1 of this Annual Report.

We are subject to compliance with environmental and occupational safety and health laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent and complex federal, state and local laws and regulations with respect to environmental protection, and the health and safety of employees. These laws and regulations may impose numerous obligations on our operations including the acquisition of permits, including drilling permits, to conduct regulated activities; the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmental sensitive areas such as wetlands, wilderness regions and other protected areas; the imposition of substantial liabilities for pollution resulting from our operations; and the application of specific health and safety criteria addressing worker protection. The Company maintains insurance common to the industry related to pollution resulting from operations. As mentioned below, prior operators releases may be unknown to the Company.

Failure to comply with these laws and regulations can result in civil and criminal fines and penalties, the imposition of investigatory, corrective action or remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose joint and several strict liability for costs required to clean up and restore sites where hazardous substances or wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We may incur significant environmental costs and liabilities in the performance of our operations as a result of our handling petroleum hydrocarbons, hazardous substances and wastes, because of air emissions and wastewater discharges relating to our operations, and due to historical industry operations and waste disposal practices by us or prior operators or other third parties over whom we had no control. For example, an accidental release of petroleum hydrocarbons from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. Please read “Operations-Environmental and Occupational Health Safety Matters” included under Part I, Item 1 of this Annual Report.

Climate change legislation and regulatory initiatives restricting emissions of GHGs may adversely affect our operations, our cost structure, or the demand for oil and natural gas.

The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.

U.S. EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities in the United States on an annual basis, which include certain of our operations. Please read “Operations-Environmental and Occupational Health Safety Matters-Climate Change” included under Part I, Item 1 of this Annual Report. These U.S. EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities, should those facilities exceed threshold permitting levels of GHG emissions.

A number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years. Please read “Operations-Environmental and Occupational Health Safety Matters-Hydraulic Fracturing” included under Part I, Item 1 of this Annual Report. Some states in which we operate, including Montana, Texas and Wyoming, have adopted and other states have considered adopting legal requirements that could impose more stringent permitting public disclosure, or well construction requirements on hydraulic fracturing activities. Other states, such as Oklahoma, have imposed restrictions on injection of produced wastewater due to induced seismicity concerns or, such as New York, prohibit hydraulic fracturing altogether. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Policy changes initiated during the first year of the new Presidential Administration could result in an increase in the overall fuel supply, lessening the demand or price for the Company’s output.

In its first year, the new Presidential Administration initiated several policy changes intended to reinvigorate coal’s use for energy production and increase the total available petroleum supply.

During its first year, the new Administration took steps to reverse policies of the prior Administration that disadvantaged coal as a fuel for energy production. On February 16, 2017, the new Administration repealed the Stream Protection Rule, which limited mountaintop mining. In March 2017, the Interior Department lifted the prior Administration’s ban on new coal leasing on federal land. In April 2017, the Court of Appeals for the District of Columbia Circuit granted the new Administration’s request to stay enforcement of mercury air emission limits while the new Administration decides whether to repeal or defend the prior Administrations limits. On June 1, 2017, the Administration announced that the United States would withdraw from the Paris Agreement, pursuant to which the country had pledged reductions in greenhouse gas emissions. On July 27, 2017, U.S. EPA issued a proposed rule rescinding the prior Administration’s Clean Water Rule, which sought to designate what water bodies are subject to the Clean Water Act’s protection and was seen as a constraint on coal mining operations. On October 10, 2017, U.S. EPA issued an Advanced Notice of Proposed Rulemaking to replace the Clean Power Plan but did not commit to any specific approach to regulating carbon emissions and instead solicited comments on whether a replacement was needed.

During its first year, the new Administration also took steps to reverse several policies of the prior Administration that restricted, or imposed additional costs on, petroleum extraction or processing. In March 2017, the new Administration reversed the prior Administration’s policy and issued a federal permit for the Keystone XL pipeline, eventually allowing processing of Alberta oil sands at refineries in the Gulf Coast. On March 28, 2017, the new Administration issued Executive Order 13783

promoting the development of energy resources and directing agency heads to review existing regulations affecting, among other things, petroleum extraction. On June 16, 2017, U.S. EPA proposed staying the 2016 Methane Rule, which imposed operating practices to limit emissions from fracturing operations and required “green completions” of fractured wells. On July 25, 2017, the Interior Department proposed a rule to rescind the prior Administration’s rule restricting flaring methane from production wells on federal lands. In a statement dated December 28, 2017, the Interior Department indicated it would propose changes in 2016 safety rules governing offshore oil and gas production (e.g., third-party certification of safety devices, safety system design requirements and failure reporting). On December 29, 2017, the new Administration rescinded rules imposing well-integrity testing, chemical use reporting, and waste fluids storage requirements on production wells on federal lands. On January 4, 2018, the Administration announced it would lift the prior Administration’s moratorium to allow new offshore oil and gas drilling in nearly all U.S. coastal waters, including off California for the first time in decades, and hold 47 lease sales over the coming years.

If they withstand whatever court challenges they might confront to become effective, and, in the case of the coal initiatives, have the effect of increasing coal’s use for energy production, these initiatives could have the effect of increasing the overall fuel supply, thereby reducing the demand for, or price of, the Company’s output.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010 comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. On May 23, 2012, the CFTC, together with the SEC, published final rules regarding the definition of “swap,” “security-based swap,” “swap dealer,” “major swap participant” and “eligible contract participant,” which impact the application of the Act and subsequent CFTC rules on derivatives market participants. The Act and the CFTC rules require derivatives market participants to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements) in connection with certain derivatives activities, and certain of our derivatives activities are subject to such requirements. In addition, on January 6, 2016, the CFTC published final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants or financial end users. While we do not anticipate being subject to margin requirements as a swap dealer, major swap participant or financial end user, application of these requirements to other market participants could affect the cost and availability of swaps we use for hedging. In addition, on December 30, 2016, the CFTC published re-proposed rules to set position limits for certain futures and options contracts in the major energy markets and for swaps that are their economic equivalent, which includes an exemption for certain bona fide hedging transactions. However, these rules have not been finalized, and their impact on our hedging activities is uncertain. Other proposed rules remain to be finalized, and the CFTC has delayed the compliance dates for various final rules previously published. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us or the timing of such effects. The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new CFTC rules could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act or the CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to resume distributions. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act or the CTC rules is to lower commodity prices. Any of these consequences could have material, adverse effect on us, our financial condition, and our results of operations.

Counterparty failure may adversely affect our derivative positions.

We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our net cash provided by operating activities, financial condition and results of operations would be adversely affected.

Increased IT security threats and more sophisticated and targeted computer crime could pose a risk to our systems, networks, products, facilities and services.

Increased information security threats and more sophisticated, targeted computer crime pose a risk to the confidentiality, availability and integrity of our data, operations and infrastructure. In addition, the Company maintains interfaces with certain third-party service providers. Threats to information security also exist in the processing of customer information through various other vendors and their personnel. While we attempt to mitigate these risks by employing a number of measures, including security measures, employee training, comprehensive monitoring of our networks and systems, and maintenance of backup and protective systems, our employees, systems, networks, products, facilities and services remain potentially vulnerable to sophisticated espionage or cyber-assault. Depending on their nature and scope, such threats could potentially lead to the compromise of confidential information, improper use of our systems and networks, manipulation and destruction of data, defective products, production downtimes and operational disruptions, which in turn could adversely affect our reputation, competitiveness and results of operations.

Locations that we or the operators of our properties decide to drill may not yield oil or natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we or the operators of our properties drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. If we or the operators of our properties drill future wells that we identify as dry holes, our drilling success rate would decline and may adversely affect our results of operations.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash flows from operations.

Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGLs prices, the generation of additional seismic or geological information, the availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing leasehold acreage. As of December 31, 2017, we have identified 3,233 (gross) drilling locations. These identified drilling locations represent a significant part of our strategy. The SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.

Our ability to drill and develop these locations depends on a number of factors, including, among others, the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, drilling and operating costs and drilling results. As we have not assigned any proved reserves to the drilling locations we have identified and scheduled for drilling, there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected time frame or will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial position and results of operations.

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including, but not limited to:


•	the high cost, shortages or delivery delays of equipment and services;


•	shortages of or delays in obtaining water for hydraulic fracturing operations;


•	unexpected operational events and conditions;


•	adverse weather conditions;


•	human errors;


•	facility or equipment malfunctions;


•	title deficiencies that can render a lease worthless;


•	compliance with environmental and other governmental requirements;


•	unusual or unexpected geological formations;


•	loss of drilling fluid circulation;


•	formations with abnormal pressures;


•	environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;


•	fires;


•	blowouts, craterings and explosions;


•	uncontrollable flows of oil, natural gas or well fluids; and


•	pipeline capacity curtailments.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Seasonal weather conditions, severe weather events, and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Seasonal anomalies such as hot summers or mild winters sometimes impact this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers, joint interest owners and by counterparties to our price risk management arrangements. Some of our vendors, customers, joint interest owners and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers, joint interest owners and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’, customers’, joint interest owners’ and counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers, joint interest owners and/or counterparties could reduce our revenues.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend on senior management personnel, each of whom would be difficult to replace.

We depend on the performance of R. Scott Sloan, our President and Chief Executive Officer, and Ryan Midgett, our Chief Financial Officer. We do not maintain key person insurance for either of Mr. Sloan or Mr. Midgett. The loss of either or both of Messrs. Sloan and Midgett could negatively impact our ability to execute our strategy and our results of operations.

We may be unable to compete effectively with larger companies in the oil and natural gas industry.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGLs prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with our larger competitors that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Federal securities laws could limit our ability to book additional proved undeveloped reserves in the future.

Under the federal securities laws, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

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

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance

for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the Tax Cuts and Jobs Act of 2017 (the “Tax Act”), which was signed on December 22, 2017, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. It is unclear whether any of the foregoing or similar proposals will be considered and enacted as part of future tax reform legislation and if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and any such change could have an adverse effect on our financial position, results of operations and cash flows.

Recent changes in U.S. federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition.

The Tax Act, signed on December 22, 2017, may affect our cash flows, results of operations and financial condition. Among other items, the Tax Act repealed the deduction for certain U.S. production activities and provided for a new limitation on the deduction for interest expense. Given the scope of this law and the potential interdependency of its changes, it is difficult at this time to assess whether the overall effect of the Tax Act will be cumulatively positive or negative for our earnings and cash flow, but such changes may adversely impact our financial results.

Risks Related to Our Common Stock

The price of our Predecessor’s common units was historically volatile. This volatility may continue and may negatively affect the price of our Common Stock.

Our Predecessor’s common units experienced substantial price volatility, and our Common Stock may continue to experience substantial price volatility. This volatility may negatively affect the price of our Common Stock at any point in time. Our stock price is likely to continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors, including:


•	announcements concerning our competitors, the oil and gas industry or the economy in general;


•	fluctuations in the prices of oil, natural gas and NGLs;


•	general and industry-specific economic conditions;


•	changes in financial estimates or recommendations by securities analysts or failure to meet analysts’ performance expectations;


•	additions or departures of key members of management;


•	lack of trading liquidity;


•	any increased indebtedness we may incur in the future;


•	speculation or reports by the press or investment community with respect to us or our industry in general;


•	announcements by us or our competitors of significant contracts, acquisitions, dispositions, strategic partnerships, joint ventures or capital commitments;


•	changes or proposed changes in laws or regulations affecting the oil and gas industry or enforcement of these laws and regulations, or announcements relating to these matters; and


•	general market, political and economic conditions, including any such conditions and local conditions in the markets in which we operate.

Broad market and industry factors may decrease the market price of our Common Stock, regardless of our actual operating performance. The stock market in general has from time to time experienced extreme price and volume fluctuations, including periods of sharp decline. In the past, following periods of volatility in the overall market and the market price of a company’s

securities, securities class action litigation has often been instituted against these companies. Such litigation, if instituted against us, could result in substantial costs and be a diversion of our management’s attention and resources.

In addition, sales of our Common Stock by existing stockholders, or the perception that these sales may occur, especially by directors or significant stockholders of the Company, may cause our stock price to decline.

The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our Common Stock.

Our outstanding share capital consists of approximately 20.1 million shares of Common Stock. In connection with our emergence from bankruptcy, we issued (i) to electing holders of Predecessor’s preferred equity, three and a half year warrants (the “Preferred Unit Warrants”), which are exercisable to purchase up to 621,649.49 shares of the Common Stock as of the Effective Date, subject to dilution, at a strike price of $44.25 and (ii) to electing holders of the Predecessor’s common equity, three and a half year warrants (the “Common Unit Warrants” and, together with the Preferred Unit Warrants, the “Warrants”), which are exercisable to purchase up to 640,875.75 shares of the Common Stock as of the Effective Date, subject to dilution, at a strike price of $61.45. The Warrants expire on February 1, 2021. Additionally, an aggregate of 2,233,333 shares of Common Stock are available for grant to certain of our employees pursuant to awards under the MIP. The exercise of equity awards, including any stock options that we may grant in the future, and Warrants, and the sale of shares of our Common Stock underlying any such options or the Warrants, could have an adverse effect on the market for our Common Stock, including the price that an investor could obtain for their shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of the Warrants and any stock options that may be granted or issued pursuant to the MIP in the future.

Our Common Stock is listed on the OTCQX marketplace and is held by a small group of investors.

Our Common Stock is quoted on the OTCQX under the symbol “VNRR.” The lack of market and float of our Common Stock can have an adverse effect on the market liquidity of our Common Stock and, as a result, the market price for our Common Stock could become more volatile. If we do not re-list our Common Stock on a national securities exchange and seek to increase its trading liquidity, it may be difficult to attract the interest of analysts, institutional investors, investment funds and brokers.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with Marathon Asset Management, L.P., Contrarian Capital Management, L.L.C., Morgan Stanley & Co. LLC, Monarch Alternative Capital LP, J.P. Morgan Securities LLC, and FMR LLC collectively owned approximately 75.4% of our outstanding Common Stock as of March 16, 2018. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, if such action, in their judgment, could enhance their investment in the Company. Such transactions might adversely affect us or other holders of our Common Stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our Common Stock because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Future sales of our Common Stock in the public market or the issuance of securities senior to our Common Stock, or the perception that these sales may occur, could adversely affect the trading price of our Common Stock and our ability to raise funds in stock offerings.

A large percentage of our shares of Common Stock is held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we filed a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our Common Stock in the public markets, or even the perception that these sales might occur (such as pursuant to the aforementioned registration statement), could cause the market price of our Common Stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We do not expect to pay dividends in the near future.

We do not intend to pay cash dividends on our Common Stock in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities. Any future dividend payments will be restricted by the terms of the agreements governing our revolving credit

facility and our Senior Notes due 2024.

Certain provisions of our Certificate of Incorporation and our Bylaws may make it difficult for stockholders to change the composition of our Board of Directors and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:


•	authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;


•	establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and


•	limit the persons who may call special meetings of stockholders.

These provisions could enable the Board to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.

We are a “smaller reporting company” and, as such, are allowed to provide less disclosure than larger public companies.

We are currently a “smaller reporting company,” as defined by Rule 12b-2 of the Exchange Act. As a “smaller reporting company,” we have certain decreased disclosure obligations in our SEC filings, which may make it harder for investors to analyze our results of operations and financial prospects and may result in less investor confidence.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in Part I, Item 1 of this Annual Report, and is incorporated herein by reference.

We have office leases in Houston and Odessa, Texas; Gillette, Wyoming; and McAlester, Oklahoma. As of December 31, 2017, the lease for the Houston office covers approximately 42,940 square feet of office space with a term ending on June 30, 2026. Our lease for the Odessa office covers approximately 6,700 square feet of office space, and runs through June 30, 2019. In Wyoming, the lease for our Gillette office covers approximately 5,000 square feet with a lease term expiring on April 30, 2018. We are also leasing a fenced yard in Gillette, Wyoming with lease term ending on March 31, 2018. Our lease for the McAlester, Oklahoma office covers approximately 1,500 square feet with a lease term ending on July 31, 2018. We also lease a storage space adjacent to the McAlester, Oklahoma office with lease term ending concurrently with the office lease. We also have leases in Eunice and Artesia, New Mexico and Mustang and Stroud, Oklahoma which are month-to-month. The total annual cost of our office leases for 2017 was approximately $1.8 million.

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

Please see “Emergence from Voluntary Reorganization under Chapter 11 Proceedings” included under Part I, Item 1 of this Annual Report for information regarding our Chapter 11 Cases.

We are also a party to separate legal proceedings as further discussed below.

Litigation Relating to Vanguard’s 2015 merger with LRR Energy, L.P.

In June and July 2015, purported unitholders of LRR Energy, L.P. (“LRE”) filed four lawsuits challenging Vanguard’s 2015 merger with LRE (the “LRE Merger”). These lawsuits were styled (a) Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, in the Court of Chancery of the State of Delaware; (b) Christopher Tiberio v. Eric Mullins et al., Cause No. 2015-39864, in the District Court of Harris County, Texas, 334th Judicial District; (c) Eddie Hammond v. Eric Mullins et al., Cause No. 2015-40154, in the District Court of Harris County, Texas, 295th Judicial District; and (d) Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, in the United States District Court for the Southern District of Texas, Houston Division. These lawsuits have been voluntarily dismissed or nonsuited.

On August 18, 2015, another purported LRE unitholder (the “LRE Plaintiff”) filed a putative class action lawsuit in connection with the LRE Merger. This lawsuit is styled Robert Hurwitz v. Eric Mullins et al., Civil Action No. 1:15-cv-00711-MAK, in the United States District Court for the District of Delaware (the “LRE Lawsuit”). On June 22, 2016, the LRE Plaintiff filed his Amended Class Action Complaint (the “Amended LRE Complaint”) against LRE, the members of the board of directors of the general partner of LRE, Vanguard, Lighthouse Merger Sub, LLC, and the members of Vanguard’s board of directors (the “LRE Lawsuit Defendants”).

In the Amended LRE Complaint, the LRE Plaintiff alleges multiple causes of action related to the registration statement and proxy statement filed with the SEC in connection with the LRE Merger (the “LRE Proxy”), including that (i) Vanguard and its directors have allegedly violated Section 11 of the Securities Act because the LRE Proxy allegedly contained misleading statements and omitted allegedly material information, (ii) the members of Vanguard’s board of directors have allegedly violated Section 15 of the Exchange Act by signing the LRE Proxy and participating in the issuance of common units in connection with the LRE Merger, (iii) the LRE Lawsuit Defendants have allegedly violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder because the LRE Proxy allegedly contained misleading statements and omitted allegedly material information, and (iv) LRE’s and Vanguard’s directors have allegedly violated Section 20(a) of the Exchange Act by allegedly controlling LRE and Vanguard in disseminating the LRE Proxy. In general, the LRE Plaintiff alleges that the LRE Proxy failed, among other things, to disclose allegedly material details concerning Vanguard’s (x) debt obligations and (y) ability to maintain distributions to unitholders. Based on these allegations, the LRE Plaintiff seeks, among other relief, to rescind the LRE Merger, and an award of damages, attorneys’ fees, and costs.

Rule of Civil Procedure 56. On December 29, 2017, the Court denied the LRE Lawsuit Defendants’ motions for summary judgment, holding that the LRE Plaintiff was entitled to complete discovery on his claims, but that the LRE Lawsuit Defendants could renew their motions for summary judgment if discovery shows there are no genuine issue of material fact precluding judgment as a matter of law in the LRE Lawsuit Defendants’ favor. On January 2, 2018, the Court granted the LRE Plaintiff’s motion for class certification, and preliminarily certified the LRE Plaintiff’s claims as a class action on behalf of certain former LRE unitholders.

Discovery is currently ongoing in the LRE Lawsuit and must be completed by May 4, 2018. The deadline to file motions for summary judgment on the LRE Plaintiff’s class claims is May 11, 2018. Jury selection and a five-day trial is set to begin on July 30, 2018.

The LRE Lawsuit Defendants believe the LRE Lawsuit is without merit and intend to vigorously defend against it. Vanguard expects that defense costs of the LRE Lawsuit Defendants and any potential liability in the LRE Lawsuit (both subject to policy limits and coverage restrictions that may limit any insurance recovery) will be covered by insurance, although it remains possible that such potential liability may exceed insurance policy limits and coverage. At this time, however, Vanguard cannot predict the outcome of the LRE Lawsuit, nor can Vanguard predict the amount of time and expense that will be required to resolve the LRE Lawsuit.

Litigation Relating to the Debt Exchange

On March 1, 2016, a purported holder of the Senior Notes due 2020, Gregory Maniatis, individually and purportedly on behalf of other non-qualified institutional buyers (“non-QIBs”) who beneficially held the Senior Notes due 2020, filed a class action lawsuit, against Vanguard and VNRF in the United States District Court for the Southern District of New York (the “Court”). The lawsuit was styled Gregory Maniatis v. Vanguard Natural Resources, LLC and VNR Finance Corp., Case No. 1:16-cv-1578. On March 18, 2016, a purported holder of the Senior Notes due 2020, William Rowland, individually and purportedly on behalf of others similarly situated filed a class action lawsuit, against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC in the United States District Court for the Southern District of New York. The lawsuit was styled, Rowland v. Vanguard Natural Resources, LLC et al, Case No. 1:16-cv-2021. On March 29, 2016, a purported holder of the Senior Notes due 2020, Lawrence Culp, individually and purportedly on behalf of others similarly situated filed a class action lawsuit, against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC. The lawsuit was styled, Culp v. Vanguard Natural Resources, LLC et al, Case No. 1:16-cv-2303. On April 12, 2016, purported holders of Senior Notes due 2020, Richard I. Kaufmann and Laura Kaufmann, individually and purportedly on behalf of others similarly situated, filed a class action lawsuit against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC in the Southern District of New York. The lawsuit was styled Kaufmann et al v. Vanguard Natural Resources, LLC et al, Case No. 1:16-cv-02743.

On April 14, 2016, the above styled lawsuits were consolidated for all purposes and captioned In re Vanguard Natural Resources Bondholder Litigation, Case No. 16-cv-01578 (the “Debt Exchange Lawsuit”). Maniatis, Rowland and Culp (the “Debt Exchange Plaintiffs”) filed an Amended Complaint in the Debt Exchange Lawsuit against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC (the “Debt Exchange Defendants”) on April 20, 2016.

The Debt Exchange Plaintiffs allege a variety of causes of action challenging the Company’s debt exchange, whereby the Debt Exchange Defendants issued the Senior Notes due 2024 in exchange for certain Senior Notes due 2020 (the “Exchange Offer”), including that the Debt Exchange Defendants have allegedly (a) violated Section 316(b) of the Trust Indenture Act of 1939 (the “TIA”) by benefiting themselves and a minority of the holders of Senior Notes due 2020 at the expense of the non-QIB holders of Senior Notes due 2020, (b) breached the terms of the indenture governing the Senior Notes due 2020 (the “Senior Notes Indenture”) and the Debt Exchange Plaintiffs’ and class members’ contractual rights under the Senior Notes Indenture, (c) breached the implied covenant of good faith and fair dealing in connection with the Exchange Offer, and (d) unjustly enriched themselves at the expense of the Debt Exchange Plaintiffs and class members by reducing indebtedness and reducing the value of the Senior Notes due 2020.

Based on these allegations, the Debt Exchange Plaintiffs seek to be declared a proper class and a declaration that the Exchange Offer violated the TIA and the Senior Notes Indenture. The Debt Exchange Plaintiffs also seek monetary damages and attorneys’ fees.

On August 10, 2016, the Debt Exchange Plaintiffs filed a Consolidated Second Amended Class Action Complaint (the “Second Amended Complaint”), in which they realleged the claims asserted in the Amended Complaint, named Vanguard Operating, LLC, Escambia Operating Co. LLC, Escambia Asset Co. LLC, Eagle Rock Upstream Development Company, Inc., Eagle Rock Upstream Development Company II, Inc., Eagle Rock Acquisition Partnership, L.P., Eagle Rock Acquisition Partnership II, L.P., Eagle Rock Energy Acquisition Co., Inc., and Eagle Rock Energy Acquisition Co., II, Inc. (collectively with the Debt Exchange Defendants , the “Defendants”) as additional defendants in the Debt Exchange Lawsuit, and added an additional breach of the Senior Notes Indenture claim.

The Defendants moved to dismiss the Second Amended Complaint in its entirety with prejudice on August 19, 2016 (the “Motion to Dismiss”) arguing that the: (1) Debt Exchange Plaintiffs lack standing; (2) Second Amended Complaint fails to plead plausible facts demonstrating that the Exchange Offer Violated the TIA; (3) Debt Exchange Plaintiffs are barred from bringing state law claims; (4) Second Amended Complaint fails to plead plausible facts demonstrating that the Exchange Offer breached the terms of the Senior Notes Indenture; (5) Second Amended Complaint fails to plead plausible facts demonstrating a breach of the implied covenant of good faith and fair dealing; (6) unjust enrichment is not available as a cause of action; and (7) declaratory judgment claims are duplicative. The Debt Exchange Plaintiffs filed an opposition to the Motion to Dismiss on September 19, 2016, and the Defendants filed a reply in further support of the Motion to Dismiss on October 7, 2016.

On February 1, 2017, while awaiting decision on the Motion to Dismiss, Defendants filed voluntary bankruptcy petitions in the United State Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Action”). The Bankruptcy Action was styled In re: Vanguard Natural Resources LLC, et al. (Case No. 17-30560). Pursuant to 11 U.S.C. §362, the Debt Exchange Lawsuit was automatically stayed and the Motion to Dismiss terminated, subject to reinstatement when either the Bankruptcy Action was terminated or the automatic stay was lifted.

On July 18, 2017, the United Stated Bankruptcy Court for the Southern District of Texas confirmed Vanguard’s Second Amended Joint Plan of Reorganization (the “Plan”) in the Bankruptcy Action, and on August 1, 2017 Vanguard emerged from bankruptcy. No proof of claim regarding the Debt Exchange Lawsuit was filed in the Bankruptcy Action and, therefore, the claim was discharged. Pursuant to the Plan, a claim injunction prohibits claims such as those brought in the Debt Exchange Lawsuit from being litigated further.

Litigation Relating to Alleged Royalty Underpayment

On December 10, 2015, a lessor in the Piceance Basin of Colorado, Retova Resources, L.P. (“Retova”), filed a class action lawsuit against Vanguard in the Colorado State District Court for the City and County of Denver (the “Colorado Court”). The lawsuit is styled Retova Resources, LP, individually and on behalf of all others similarly situated, v. Vanguard Permian, LLC & Vanguard Operating, LLC, Case Number 2015CV34352.

Retova alleges Vanguard breached the various leases, the implied covenant to market, and the duty of good faith and fair dealing. Plaintiffs claim Vanguard breached by failing to pay royalties based on the sale of marketable natural gas products and on the prices received for those products at the first commercial market under Colorado law. Based on these allegations, Retova seeks to certify a class of similarly situated lessors and overriding royalty interest owners. Retova seeks damages for royalty underpayment and corresponding pre- and post-judgment interest.

After the filing of Vanguard’s bankruptcy, Retova pursued its pre-petition and administrative class claims in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The bankruptcy proceeding is styled In re Vanguard Natural Resources, LLC, Case No. 17-30560. The Bankruptcy Court declined to consider plaintiff’s administrative claim as a class action. Subsequently, Vanguard resolved the individual administrative claim and Retova withdrew its pre-petition claims. The litigation concerning plaintiff’s allegations in the Bankruptcy Court have therefore concluded.

Retova, however, may attempt to pursue its post-confirmation class claims in the Colorado Court. Should Retova pursue post-confirmation class claims, the case would still be in the early stages of litigation with necessary discovery and class certification proceedings before the Colorado Court could address the merits of the lawsuit. We expect that the plaintiff will pursue its post-confirmation class claims, but we cannot predict the outcome of the lawsuit or the time and expense that will be required to resolve the lawsuit. Vanguard believes the lawsuit is without merit and intends to vigorously defend against it.

arise out of claims brought against us. If one or more negative outcomes were to occur relative to these matters, the aggregate impact to our financial position, results of operations or cash flow could be material. As of December 31, 2017, we have not reserved any loss contingencies related to our legal proceedings in our financial statements because our management believes a loss arising from these proceedings is not probable and reasonably estimable.

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our Common Stock is quoted on the OTCQX under the symbol “VNRR” and has been trading since September 28, 2017. No established public trading market existed for our Common Stock prior to September 28, 2017. The following table sets forth the per share range of high and low bid information for our Common Stock as reported on the OTCQX for the periods presented. On March 16, 2018, there were 20,100,178 outstanding shares of common stock and approximately seven shareholders, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or a bank. The following table presents the high and low sales price for our common units listed on OTCQX during the periods indicated, as quoted on the OTC Markets website.



	Successor
	Common Stock
	High		Low
2017
Fourth Quarter	$	21.00	$	18.25
Third Quarter (from September 28, 2017 through September 30, 2017)	$	20.50	$	17.04

Our Predecessor’s common units commenced quotation on the OTC Pink operated by the OTC Markets Group, Inc. (the “OTC Pink”) on February 13, 2017 under the symbols VNRSQ, VNRAQ, VNGBQ and VNRCQ, respectively.

Prior to the commencement of the Chapter 11 Cases, our Predecessor’s common units were traded on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group, Inc. under the symbol “VNR”. The following table presents the high and low sales price for the Predecessor’s common units listed on the OTC Pink and NASDAQ during the periods indicated.



	Predecessor
	Common Units
	High		Low
2017
Third Quarter (from July 1, 2017 through July 31, 2017)	$	0.19	$	0.03
Second Quarter	$	0.09	$	0.03
First Quarter	$	1.11	$	0.06
2016
Fourth Quarter	$	1.35	$	0.46
Third Quarter	$	2.09	$	0.86
Second Quarter	$	2.17	$	1.07
First Quarter	$	3.17	$	1.29

Distributions Declared. The following table shows the amount per unit, record date and payment date of the cash distributions our Predecessor paid on each of our common units attributable to each period presented. On February 18, 2016, our Predecessor’s board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2016 of $0.03 per common and Class B unit, or $0.36 on an annualized basis, which were paid on March 15, 2016 to Vanguard unitholders of record on March 1, 2016. On February 25, 2016, our Predecessor’s 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
	Per Unit		Record Date	Payment Date
2016
First Quarter
January	$	0.0300	March 1, 2016	March 15, 2016

Dividend Policy. We do not intend to pay cash dividends on our Common Stock in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities, and for the purposes of reducing debt. Any future dividend payments will be restricted by the terms of the agreements governing our revolving credit facility and our Senior Notes due 2024.

Equity Compensation Plans. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plans as of December 31, 2017.

Recent Sales of Unregistered Securities

As previously disclosed on Form 8-K15D5, we issued 44,220 shares of Common Stock under an exemption from the registration requirements of the Securities Act under Section 1145 of the Bankruptcy Code (an “1145 Exemption”) upon emergence. On December 21, 2017, 97% of the 44,220 shares were distributed to holders of claims arising under Predecessor’s Senior Notes, and 3% of the 44,220 shares were distributed pro rata to holders of Predecessor’s Preferred Units, in each case on account of their claims under the Plan pursuant to the 1145 Exemption.

ITEM 6. SELECTED FINANCIAL DATA

Set forth below is our summary of our consolidated financial and operating data for the periods indicated.

The selected financial data should be read together with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8. Financial Statements and Supplementary Data included in this Annual Report.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in “—Non-GAAP Financial Measure” (in thousands, except per share/unit data).



	Successor			Predecessor
	Five Months Ended December 31, 2017⁽⁴⁾			Seven Months Ended July 31, 2017⁽⁴⁾
							Year Ended December 31, ⁽³⁾
							2016⁽⁴⁾			2015		2014		2013
Statement of Operations Data:
Revenues:
Oil sales	$	72,557		$	97,496		$	169,955		$	164,111	$	268,685	$	268,922
Natural gas sales	96,236			113,587			174,263			193,496		285,439		124,513
NGLs sales	36,825			35,565			44,462			39,620		70,489		49,813
Oil, natural gas and NGLs sales	205,618			246,648			388,680			397,227		624,613		443,248
Net gains (losses) on commodity derivative contracts	(55,857		)	(24,887		)	(44,072		)	169,416		163,452		11,256
Total revenues and gains (losses) on derivatives	149,761			221,761			344,608			566,643		788,065		454,504
Costs and expenses:
Production:
Lease operating expenses	60,976			87,092			159,672			146,654		132,515		105,502
Transportation, gathering, processing and compression	19,202			—			—			—		—		—
Production and other taxes	13,145			21,186			38,637			40,576		61,874		40,430
Depreciation, depletion, amortization and accretion	71,321			58,384			149,790			247,119		226,937		167,535



Impairment of oil and natural gas properties	47,640			—			494,270			1,842,317			234,434			—
Impairment of goodwill	—			—			252,676			71,425			—			—
Exploration expense	1,365			—			—			—			—			—
Selling, general and administrative expenses ⁽¹⁾	21,658			28,810			51,518			55,076			30,839			25,942
Total costs and expenses	235,307			195,472			1,146,563			2,403,167			686,599			339,409
Income (loss) from operations	(85,546		)	26,289			(801,955		)	(1,836,524		)	101,466			115,095
Other income (expense):
Interest expense	(24,204		)	(35,276		)	(95,367		)	(87,573		)	(69,765		)	(61,148		)
Net gains (losses) on interest rate derivative contracts	—			30			(2,867		)	153			(1,933		)	(96		)
Net gain (loss) on acquisitions and divestiture of oil and natural gas properties	4,450			—			(4,979		)	40,533			34,523			5,591
Gain on extinguishment of debt	—			—			89,714			—			—			—
Other	510			783			447			237			54			69
Total other expense	(19,244		)	(34,463		)	(13,052		)	(46,650		)	(37,121		)	(55,584		)
Loss before reorganization items	(104,790		)	(8,174		)	(815,007		)	(1,883,174		)	64,345			59,511
Reorganization items	(6,488		)	908,485			—			—			—			—
Net income (loss)	(111,278		)	900,311			(815,007		)	(1,883,174		)	64,345			59,511
Less: Net income attributable to non-controlling interests	(132		)	(13		)	(82		)	—			—			—
Net income (loss) attributable to Vanguard stockholders/unitholders	(111,410		)	900,298			(815,089		)	(1,883,174		)	64,345			59,511
Less: Distributions to Preferred unitholders	—			(2,230		)	(26,758		)	(26,759		)	(18,197		)	(2,634		)
Net income (loss) attributable to Common stockholders/Common and Class B unitholders	$	(111,410	)	$	898,068		$	(841,847	)	$	(1,909,933	)	$	46,148		$	56,877
Net Income (Loss) Per Share/Unit:
Basic	$	(5.55	)	$	6.84		$	(6.41	)	$	(19.80	)	$	0.56		$	0.78
Diluted	$	(5.55	)	$	6.84		$	(6.41	)	$	(19.80	)	$	0.55		$	0.77
Distributions Declared Per Common and Class B Unit	$	—		$	—		$	0.06		$	1.42		$	2.52		$	2.46
Weighted Average Common Shares/Units Outstanding:
Basic	20,059			130,962			130,903			96,048			81,611			72,644
Diluted	20,059			130,962			130,903			96,048			82,039			72,992
Weighted Average Class B Units Outstanding	—			420			420			420			420			420
Cash Flow Data:
Net cash provided by operating activities	$	37,782		$	52,288		$	290,280		$	370,084		$	339,752		$	260,965
Net cash provided by (used in) investing activities	$	(29,526	)	$	76,836		$	206,822		$	(128,144	)	$	(1,446,202	)	$	(397,977	)
Net cash provided by (used in) financing activities	$	(33,104	)	$	(151,471	)	$	(447,145	)	$	(241,940	)	$	1,094,632		$	137,267
Other Financial Information:
Adjusted EBITDA attributable to Vanguard shareholders/unitholders⁽²⁾	$	79,627		$	115,242		$	432,965		$	396,829		$	421,445		$	309,745


(1)	Includes $0.1 million, $5.8 million, $10.2 million, $18.5 million, $11.7 million and $5.9 million of non-cash unit-based compensation expense for the five months ended December 31, 2017 (Successor), seven months ended July 31, 2017 and in 2016, 2015, 2014 and 2013 (Predecessor), respectively.


(2)	See “—Non-GAAP Financial Measure” below.


(3)	From 2013 through 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets. The operating results of these properties were included with ours from the closing date of the acquisitions forward.


(4)	In 2017 and 2016, we completed the divestiture of oil and natural gas properties in the SCOOP/STACK area in Oklahoma and in our other operating areas. As such, there are no operating results from these properties included in our operating results from the closing date of the divestiture forward.



	Successor		Predecessor
			As of December 31,
(in thousands)	As of December 31, 2017		2016			2015			2014		2013
Balance Sheet Data:
Cash and cash equivalents	$	2,762	$	49,957		$	—		$	—	$	11,818
Short-term derivative assets	2,258		—			236,886			142,114		21,314
Other current assets	78,437		105,082			121,636			144,119		73,025
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment	1,533,392		858,253			1,721,976			2,975,806		1,810,517
Long-term derivative assets	—		—			80,161			83,583		60,474
Goodwill⁽¹⁾	—		253,370			506,046			420,955		420,955
Other assets	26,671		42,626			28,887			11,755		74,039
Total Assets	$	1,643,520	$	1,309,288		$	2,695,592		$	3,778,332	$	2,472,142
Short-term derivative liabilities	$	39,212	$	125		$	356		$	3,583	$	10,992
Long-term debt classified as current ⁽²⁾	—		1,753,345			—			—		—
Other current liabilities	120,872		135,213			201,652			175,021		114,411
Long-term debt ⁽²⁾	905,976		15,475			2,277,931			1,917,556		990,380
Long-term derivative liabilities	27,483		—			—			1,380		4,085
Other long-term liabilities	152,449		303,995			303,088			146,676		83,939
Stockholders'/Members’ equity (deficit)	397,528		(898,865		)	(87,435		)	1,534,116		1,268,335
Total Liabilities and Stockholders'/Members’ Equity	$	1,643,520	$	1,309,288		$	2,695,592		$	3,778,332	$	2,472,142


(1)	Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Purchase completed on December 31, 2010 and the LRE Merger completed on October 5, 2015.


(2)	As a result of our Chapter 11 filing, we classified our debt under our Reserve-Based Credit Facility, Second Lien Secured Notes, Senior Notes due 2020 and Senior Notes 2019 as current at December 31, 2016.

Summary Reserve and Operating Data

The following tables show estimated net proved reserves based on a reserve report prepared by us and audited by independent petroleum engineers, Miller and Lents, and certain summary unaudited information with respect to our production and sales of oil, natural gas and NGLs. You should refer to Risk Factors under Part I, Item 1A and Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this Annual Report and, “Oil, Natural Gas and NGLs Data—Estimated Proved Reserves” and “Oil, Natural Gas and NGLs Data—Production and Price History” included under Part I, Item I of this Annual Report when evaluating the material presented below.



	As of December 31, 2017
Reserve Data:
Estimated net proved reserves:
Crude oil (MMBbls)	39.0
Natural gas (Bcf)	1,357.6
NGLs (MMBbls)	38.4
Total (Bcfe)	1,821.5
Proved developed (Bcfe)	1,225.3
Proved undeveloped (Bcfe)	596.2
Proved developed reserves as % of total proved reserves	67		%
PV-10 ⁽¹⁾	$	1,194.8
Less: Future income taxes (discounted at 10%)	(121.2		)
Standardized Measure (in millions) ⁽²⁾	$	1,073.6
Representative Oil and Natural Gas Prices ⁽³⁾:
Oil—WTI per Bbl	$	51.22
Natural gas—Henry Hub per MMBtu	$	2.99
NGLs—Volume-weighted average price per Bbl	$	19.24

(1)

(2)

Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the 12-month unweighted average of first-day-of-the-month price) and calculated net of the estimated future costs incurred in developing, producing and abandoning the proved reserves. Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Item 1. Business—Operations—Price Risk Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

(3)

Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month unweighted average of first-day-of-the-month commodity prices (the “12-month average price”) for January through December 2017, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using the differentials to the crude oil 12-month average price per Bbl of $51.22.



	Net Production⁽¹⁾			Average Realized Sales Prices ⁽²⁾							Production Cost ⁽³⁾
	Crude Oil Bbls/day	Natural Gas Mcf/day	NGLs Bbls/day	Crude Oil Per Bbl		Natural Gas Per Mcf		NGLs Per Bbl			Per Mcfe
Year Ended December 31, 2017
Pinedale (Green River Basin)	796	92,038	1,310	$	46.15	$	2.37	$	18.91		$	0.47
Mamm Creek (Piceance Basin)	535	45,704	3,676	$	41.47	$	2.27	$	14.16		$	0.56
All other fields	8,993	119,816	4,108	$	42.57	$	2.22	$	25.06		$	1.60
Total	10,324	257,558	9,094	$	42.38	$	2.28	$	19.77		$	1.08

Year Ended December 31, 2016
Pinedale (Green River Basin)	844	97,323	958	$	59.58	$	3.40	$	(1.72	)	$	0.44
Mamm Creek (Piceance Basin)	579	50,166	3,746	$	52.21	$	2.39	$	11.65		$	0.53
All other fields	11,308	147,885	5,449	$	53.34	$	2.85	$	16.86		$	1.40
Total	12,731	295,374	10,153	$	53.20	$	2.95	$	13.19		$	1.01

Year Ended December 31, 2015
Pinedale (Green River Basin)	804	98,266	1,932	$	58.87	$	2.37	$	0.26		$	0.54
Mamm Creek (Piceance Basin)	649	58,764	3,701	$	49.30	$	1.96	$	12.18		$	0.43
All other fields	9,529	135,066	3,927	$	57.24	$	2.07	$	21.71		$	1.41
Total	10,982	292,096	9,560	$	56.89	$	3.13	$	13.68		$	0.96


(1)	Average daily production calculated based on 365 days for 2017, 366 days for 2016, and 365 days for 2015, and includes production for all of our acquisitions from the closing dates of these acquisitions.

(2)

Average realized sales prices include the impact of hedges but exclude 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 average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Management’s Discussion and Analysis of Financial Condition-Year Ended December 31, 2017 compared to Year Ended December 31, 2016” and “Management’s Discussion and Analysis of Financial Condition -Year Ended December 31, 2016 compared to Year Ended December 31, 2015” under Part II, Item 7 of this Annual Report.


(3)	Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).

Non-GAAP Financial Measure

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard stockholders/unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that begins with net income (loss) attributable to Vanguard stockholders/unitholders plus net income (loss) attributable to non-controlling interest. The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:


•	Net interest expense;


•	Depreciation, depletion, amortization and accretion;


•	Impairment of oil and natural gas properties;


•	Impairment of goodwill;


•	Change in fair value of commodity derivative contracts;


•	Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period;


•	Fair value of derivative contracts acquired that apply to contracts settled during the period;


•	Fair value of restructured derivative contracts;


•	Cash settlements paid on termination of derivative contracts;


•	Net gains or losses on interest rate derivative contracts;


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


•	Gain on extinguishment of debt;


•	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 and restructuring costs;


•	Material costs incurred on strategic transactions; and


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

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

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

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.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA (in thousands).



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Years Ended December 31,

							2016			2015			2014			2013
Net income (loss) attributable to Vanguard stockholders/unitholders	$	(111,410	)	$	900,298		$	(815,089	)	$	(1,883,174	)	$	64,345		$	59,511
Add: Net income attributable to non-controlling interest	132			13			82			—			—			—
Net income (loss)	(111,278		)	900,311			(815,007		)	(1,883,174		)	64,345			59,511
Plus:
Interest expense	24,204			35,276			95,367			87,573			69,765			61,148
Depreciation, depletion, amortization and accretion	71,321			58,384			149,790			247,119			226,937			167,535
Impairment of oil and natural gas properties	47,640			—			494,270			1,842,317			234,434			—
Impairment of goodwill	—			—			252,676			71,425			—			—
Change in fair value of commodity derivative contracts^(a)	39,543			24,894			309,326			61,627			(174,571		)	(10,771		)
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period ^(a)	—			—			292			5,434			—			220
Fair value of derivative contracts acquired that apply to contracts settled during the period ^(a)	—			—			15,285			44,761			21,306			30,200
Fair value of restructured derivative contracts ^(a)	—			—			—			(69,515		)	—			—
Cash settlements paid on termination of derivative contracts^(b)	4,140			—			—			—			—			—
Net (gains) losses on interest rate derivative contracts^(c)	—			(30		)	2,867			(153		)	1,933			96
Net (gain) loss on acquisitions and divestitures of oil and natural gas properties	(4,450		)	—			4,979			(40,533		)	(34,523		)	(5,591		)
Gain on extinguishment of debt	—			—			(89,714		)	—			—			—
Texas margin taxes	—			(634		)	(3,307		)	(266		)	(630		)	601
Compensation related items	81			5,797			10,183			18,522			11,710			5,931
Reorganization and restructuring costs	6,488			(908,485		)	3,156			—			—			—
Material costs incurred on strategic transactions	2,000			—			3,265			11,692			739			865
Adjusted EBITDA before non-controlling interest	$	79,689		$	115,513		$	433,428		$	396,829		$	421,445		$	309,745
Non-controlling interest attributable to adjustments above	(62		)	(271		)	(463		)	—			—			—
Adjusted EBITDA attributable to Vanguard stockholders/unitholders	$	79,627		$	115,242		$	432,965		$	396,829		$	421,445		$	309,745

(a) These items are included in the net gains (losses) on commodity derivative contracts line item in the consolidated statements of operations as follows:
	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Years Ended December 31,

							2016			2015			2014			2013
Net cash settlements (paid) received on matured commodity derivative contracts	$	(12,174	)	$	7		$	226,876		$	211,723		$	10,187		$	30,905
Change in fair value of commodity derivative contracts	$	(39,543	)	$	(24,894	)	$	(309,326	)	$	(61,627	)	$	174,571		$	10,771
Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period	$	—		$	—		$	(292	)	$	(5,434	)	$	—		$	(220	)



Fair value of derivative contracts acquired that apply to contracts settled during the period	$	—		$	—		$	(15,285	)	$	(44,761	)	$	(21,306	)	$	(30,200	)
Cash settlements paid on terminated derivative contracts^(b)	$	(4,140	)	$	—		$	—		$	—		$	—		$	—
Fair value of restructured derivative contracts ^(d)	$	—		$	—		$	53,955		$	69,515		$	—		$	—
Net gains (losses) on commodity derivative contracts	$	(55,857	)	$	(24,887	)	$	(44,072	)	$	169,416		$	163,452		$	11,256


(b)	Adjusted EBITDA attributable to Vanguard shareholders for the five months ended December 31, 2017 excludes cash settlements paid on the terminated commodity derivative contracts covering future production from assets divested in 2017.



(c) Net gains (losses) on interest rate derivative contracts as shown on the consolidated statements operations is comprised of the following:
	Successor		Predecessor
	Five Months Ended December 31, 2017		Seven Months Ended July 31, 2017			Years Ended December 31,

						2016			2015			2014			2013
Change in fair value of interest rate derivative contracts	$	—	$	125		$	10,531		$	5,379		$	2,102		$	3,792
Net cash settlements paid on interest rate derivative contracts	$	—	$	(95	)	$	(13,398	)	$	(5,226	)	$	(4,035	)	$	(3,888	)
Net gains (losses) on interest rate derivative contracts	$	—	$	30		$	(2,867	)	$	153		$	(1,933	)	$	(96	)

(d)

Adjusted EBITDA attributable to Vanguard unitholders for the year ended December 31, 2016 includes proceeds from the monetization of commodity derivative contracts of $54.0 million of which $37.1 million is attributable to derivative contracts that would have matured in 2017 and 2018. Excluding the proceeds attributable to the 2017 and 2018 commodity derivative contracts, Adjusted EBITDA available to Vanguard unitholders for the year ended December 31, 2016 amounted to $395.8 million.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS

You should read the following discussion and analysis in conjunction with Part II, Item 6 of this Annual Report and the accompanying financial statements and related notes included elsewhere in this Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in Part I, Item 1A of this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

As discussed in Notes 1 and 3 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, the Company applied fresh-start accounting upon emergence from bankruptcy on August 1, 2017, using a Convenience Date of July 31, 2017, at which time it became a new entity for financial reporting purposes. The effects of the Plan of Reorganization (described below) and the application of fresh-start accounting were reflected in our consolidated financial statements as of July 31, 2017 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the period February 1, 2017 to July 31, 2017 (predecessor). References to the Successor relate to the Company on and subsequent to the Effective Date. References to Predecessor refer to the Company prior to the Effective Date.

Overview

We are an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. The Company is currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner. Through our operating subsidiaries, as of December 31, 2017, we own properties and oil and natural gas reserves primarily located in nine operating basins:


•	the Green River Basin in Wyoming;


•	the Piceance Basin in Colorado;


•	the Permian Basin in West Texas and New Mexico;


•	the Arkoma Basin in Arkansas and Oklahoma;


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


•	the Big Horn Basin in Wyoming and Montana;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

At December 31, 2017, we owned working interests in 11,287 gross (3,902 net) productive wells. Our operated wells accounted for approximately 43% of our total estimated proved reserves at December 31, 2017. Our average net daily production was 374,063 Mcfe/day for the year ended December 31, 2017 and was 362,011 Mcfe/day for the fourth quarter of 2017. Our total estimated proved reserves at December 31, 2017 were 1,821.5 Bcfe, of which approximately 13% were oil reserves, 75% were natural gas reserves and 12% were NGLs reserves. Of these total estimated proved reserves, approximately 67% were classified as proved developed.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

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 Debtors satisfied all conditions precedent under the Final Plan and emerged from bankruptcy on August 1, 2017 (the “Effective Date”). The Successor reorganized as a Delaware corporation named Vanguard Natural Resources, Inc. on the Effective Date.

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 WTI crude oil spot price per barrel during the years ended December 31, 2016 and 2017 ranged from a low of $26.19 to a high of $60.46 and the Henry Hub natural gas spot price per MMBtu during the same period ranged from a low of $1.49 to a high of $3.80. NGLs prices were similarly volatile. As of March 12, 2018, the WTI crude oil spot price per barrel was $61.35 and the Henry Hub natural gas spot price per MMBtu was $2.78. 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.

To illustrate the impact of a volatile 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 December 31, 2017 would decrease from 1,821.5 Bcfe to 1,191.8 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 2023) at March 12, 2018, our total proved reserves as of December 31, 2017 would decrease from 1,821.5 Bcfe to 1,808.0 Bcfe. Below is a tabular presentation of the prices depicted in illustration (2) which differ from the SEC 12-month average pricing of $2.99 per MMBtu for natural gas and $51.22 per barrel of crude oil (held constant):



	2018	2019	2020	2021	2022	2023 ⁽¹⁾
Oil ($/Bbl)	$60.33	$56.78	$54.08	$52.38	$51.66	$51.57
Gas ($/MMBtu)	$2.89	$2.83	$2.75	$2.78	$2.82	$2.86

(1) Prices for 2023 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 $2.99 per MMBtu for natural gas and $51.22 per barrel of crude oil used to generate our December 31, 2017 (“4Q17”) reserve report, the average annual prices for oil, the price for each annual year presented above is slightly higher than the 4Q17 reserve report price, however the price for natural gas decreased slightly. The impact of the relative consistency in forward prices to gas wells and oil wells, when compared to the 4Q17 reserve report prices, includes stability in projected economic lives and economically recoverable volumes, despite the minor movement in prices. The following table compares the 4Q17 reserve report volumes by product with the strip pricing volumes:



	Net Oil (Bbls)	Net Gas (MMcf)	Net NGL (Bbls)	Net Bcfe
Reserve Report at 4Q17	38,970	1,357,589	38,355	1,821.5
March 12, 2018 NYMEX Strip Price	39,071	1,344,733	38,132	1,808.0
% Difference	—%	(1)%	(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.

Hedging Activities

In June 2017, we entered into commodity derivative contracts primarily with counterparties that are also lenders under our Successor Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production commencing with August 2017 production volumes. The Company generally expects to hedge more than 75% of its projected oil and natural gas proved developed production over a three to four year period. These hedges will provide some cash flow certainty regardless of the volatility in commodity prices.

Capital Development

The Board approved an initial capital expenditures budget for 2018 of $160.0 million compared to the $63.8 million and $46.1 million we spent during the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Our initial 2018 capital expenditures budget includes approximately $135.0 million of drilling and completion capital, or 85% of the total capital budget. More than 97% of the drilling and completion capital is focused on the core growth assets of the Green River, Piceance and Arkoma Basins. We expect to spend between $90.0 million to $95.0 million or approximately 69% of the drilling capital budget in the Green River Basin at the Pinedale field where we will participate as a non-operated partner in the drilling and completion of vertical and horizontal wells. Additionally, we expect to spend between $20.0 million to $26.0 million or approximately 15% of the drilling capital budget in the Piceance Basin, at the Mamm Creek field where we will operate a one rig program drilling and completing vertical gas wells. We also expect to spend approximately 13% of our budgeted drilling capital in the Arkoma Basin in Oklahoma where we will be participating as a non-operated partner with Newfield and BP in a one rig program drilling and completing horizontal Woodford wells. The remaining drilling and completion capital will be spent on additional drilling, completion and production uplift projects in the Permian, Big Horn, and Powder River Basins. The Company intends to release a revised 2018 capital expenditures budget and other guidance with the release of its first quarter results that will include, among other items, the impact of reduced rig counts with increased horizontal development spending in the Pinedale field.

Results of Operations

In addition to adopting fresh-start accounting, the Successor also adopted the successful efforts method of accounting as of July 31, 2017. Prior to July 31, 2017, the Predecessor used the full-cost method of accounting. Further, in conjunction with the application of fresh-start accounting, we adopted ASC Topic 606 which had the effect of increasing revenues and expenses by $19.2 million during the five months ended December 31, 2017. The results of operations of the Successor and the Predecessor are not comparable in 2017 nor are they individually comparable with prior periods. We believe however, that production volumes, oil, natural gas and NGLs revenues, lease operating expenses and production and other taxes are generally comparable. Consequently, certain of the tables and discussions below include combined results of the Predecessor and the Successor together for the periods in 2017 for these operational items. We believe this combined presentation gives the reader a better understanding of our operational results in 2017.

The following table sets forth selected financial and operating data for the periods indicated.



	Successor			Predecessor
	Five Months Ended December 31, 2017⁽¹⁾			Seven Months Ended July 31, 2017⁽¹⁾			Years Ended December 31,⁽¹⁾
							Combined			Predecessor			Predecessor
							2017			2016			2015
Revenues:
Oil sales	$	72,557		$	97,496		$	170,053		$	169,955		$	164,111
Natural gas sales	96,236			113,587			209,823			174,263			193,496
Natural gas liquids sales	36,825			35,565			72,390			44,462			39,620
Oil, natural gas and NGLs sales	205,618			246,648			452,266			388,680			397,227
Net gains (losses) on commodity derivative contracts	(55,857		)	(24,887		)	(80,744		)	(44,072		)	169,416
Total revenues and gains (losses) on derivatives	$	149,761		$	221,761		$	371,522		$	344,608		$	566,643
Costs and expenses:
Production:
Lease operating expenses	60,976			87,092			148,068			159,672			146,654
Transportation, gathering, processing and compression	19,202			—			19,202			—			—
Production and other taxes	13,145			21,186			34,331			38,637			40,576
Depreciation, depletion, amortization and accretion	71,321			58,384			129,705			149,790			247,119
Impairment of oil and natural gas properties	47,640			—			47,640			494,270			1,842,317
Impairment of goodwill	—			—			—			252,676			71,425
Exploration expense	1,365			—			1,365			—			—
Selling, general and administrative expenses:
Non-cash compensation	81			5,797			5,878			10,183			18,522
Other (excluding non-cash compensation)	21,577			23,013			44,590			41,335			36,554
Total costs and expenses	$	235,307		$	195,472		$	430,779		$	1,146,563		$	2,403,167
Other income and expenses:
Interest expense	$	(24,204	)	$	(35,276	)	(59,480		)	$	(95,367	)	$	(87,573	)
Net gains (losses) on interest rate derivative contracts	$	—		$	30		30			$	(2,867	)	$	153
Net gain (loss) on acquisitions of oil and natural gas properties	$	4,450		$	—		4,450			$	(4,979	)	$	40,533
Gain on extinguishment of debt	$	—		$	—		—			$	89,714		$	—
Other	$	510		$	783		1,293			$	447		$	237
Reorganization items	$	(6,488	)	$	908,485		901,997			$	—		$	—


(1)	During 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward. During

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.

The Five Months Ended December 31, 2017 (Successor) and the Seven Months Ended July 31, 2017 (Predecessor) Compared to Year Ended December 31, 2016 (Predecessor)

Revenues

Oil, natural gas and NGLs sales were $205.6 million, $246.6 million, and $388.7 million for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor), and the year ended December 31, 2016 (Predecessor), respectively. The key revenue measurements were as follows:



	Successor⁽¹⁾		Predecessor⁽¹⁾		Combined		Predecessor⁽¹⁾
	Five Months Ended December 31, 2017		Seven Months Ended July 31, 2017		Year Ended December 31, 2017		Year Ended December 31, 2016
	Five Months Ended December 31, 2017		Seven Months Ended July 31, 2017		Year Ended December 31, 2017		Year Ended December 31, 2016
Average realized prices, excluding hedging:
Oil (Price/Bbl)	$	47.79	$	43.33	$	45.13	$	36.47
Natural Gas (Price/Mcf)	$	2.49	$	2.05	$	2.23	$	1.61
NGLs (Price/Bbl)	$	27.70	$	17.87	$	21.81	$	11.97

Average realized prices, including hedging ⁽²⁾:
Oil (Price/Bbl)	$	40.97	$	43.34	$	42.38	$	53.20
Natural Gas (Price/Mcf)	$	2.62	$	2.05	$	2.28	$	2.95
NGLs (Price/Bbl)	$	22.62	$	17.87	$	19.77	$	13.19

Average NYMEX prices:
Oil (Price/Bbl)	$	52.69	$	49.72	$	50.88	$	42.68
Natural Gas (Price/Mcf)	$	2.95	$	3.22	$	3.11	$	2.44

Total production volumes:
Oil (MBbls)	1,518		2,250		3,768		4,660
Natural Gas (MMcf)	38,634		55,375		94,009		108,107
NGLs (MBbls)	1,329		1,990		3,319		3,716
Combined (MMcfe)	55,719		80,814		136,533		158,359

Average daily production volumes:
Oil (Bbls/day)	9,923		10,613		10,324		12,731
Natural Gas (Mcf/day)	252,512		261,201		257,558		295,374
NGLs (Bbls/day)	8,688		9,387		9,094		10,153
Combined (Mcfe/day)	364,177		381,198		374,063		432,676

(1)

During 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. During 2016, we also acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.


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

The overall increase in oil, natural gas and NGLs sales during 2017 compared to 2016 was due in part to the increase in the average realized oil and natural gas prices, excluding hedges. The adoption of Accounting Standards Codification (“ASC”) Topic

606, Revenue from Contracts with Customers (“ASC Topic 606”) also increased natural gas and NGLs revenue by $19.2 million during the Successor period due to the reclass of gathering, transportation, and processing fees related to certain of our natural gas and NGLs marketing and processing agreements. Refer to Note 4 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further details.

On a Mcfe basis, our total production decreased by 21,826 MMcfe or 14% for the year ended December 31, 2017 over the comparable period in 2016. The increase in sales due to pricing and the change in presentation was partially offset by an overall decrease in average daily production which decreased to approximately 364 MMcfe/day and 381 MMcfe/day for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively, from approximately 433 MMcfe/day for the year ended December 31, 2016 (Predecessor). The decrease in average daily production was a result of the divestitures completed during 2017.

On a Mcfe basis, crude oil production accounted for 16%, 17% and 18% of our production during the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor), and the year ended December 31, 2016 (Predecessor), respectively. Natural gas accounted for 69%, during the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), compared to 68% during the year ended December 31, 2016 (Predecessor). On a Mcfe basis, NGLs production accounted for 14%, 15%, and 14% of our production during the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor), and the year ended December 31, 2016 (Predecessor), respectively.

Hedging and Price Risk Management Activities

We recognized a net loss on commodity derivative contracts of $55.9 million and $24.9 million during the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Net cash settlements on matured commodity derivative contracts included payments of $12.2 million and receipts of $0.01 million during the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. In addition, we paid net cash settlements of $4.1 million on the monetization of commodity derivative contracts that were terminated as they relate to production of our divested properties during the five months ended December 31, 2017 (Successor). Our hedging program is intended to mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and, by us paying 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 workover expenses. Lease operating expenses on a per Mcfe basis were $1.09, $1.08, and $1.01 for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the year ended December 31, 2016 (Predecessor), respectively. The lease operating expenses per Mcfe in the Successor and Predecessor period during 2017 was higher compared to the year ended December 31, 2016 primarily due to lower production volumes as a result of decreased operational activity and divestitures completed in 2017. Overall, spending during 2017 decreased as compared to 2016 as a result of our continued focus on cost efficiency measures.

Transportation, gathering, processing and compression fees represent third-party costs related to certain of our natural gas and NGLs marketing and processing agreements. These expenses increased by $19.2 million for the five months ended December 31, 2017 (Successor) due to the adoption of Topic ASC 606 in conjunction with fresh-start accounting. In the Predecessor period, these costs were included in the net proceeds received from processing; however, natural gas and NGLs revenues and related marketing and processing costs are recognized on a gross basis effective August 1, 2017. Refer to Note 4 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further details.

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 and county and are based on the value of our reserves. As a percentage of wellhead revenues, production, severance, and ad valorem taxes was 6.39%, 8.59%, and 9.94% for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor), and the year ended December 31, 2016 (Predecessor), respectively. The tax rates in both the Successor and Predecessor periods during 2017 are lower due to the recognition of production and ad valorem taxes based on actual tax assessments which reflected lower rates than in previous periods. Additionally, the tax rate in the Successor period is further lowered by the increase in reported natural gas and NGLs revenue of $19.2 million during the Successor period due to the recording of gathering, transportation, and processing fees related to certain of our natural gas and NGLs marketing and processing agreements on a gross basis under ASC Topic 606. We record and remit production taxes based on net proceeds received from processing related to these contracts. When using net proceeds in the calculation, the effective tax rate for the Successor period is 7.05%.

Depreciation, depletion, amortization and accretion was $71.3 million, $58.4 million and $149.8 million for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the year ended December 31, 2016 (Predecessor), respectively. Depletion expense in the 2016 and 2017 Predecessor periods is lower on a per Mcfe basis due to a lower depletion base as a result of the non-cash ceiling impairment charges recorded during 2015 and 2016 and the divestitures of oil and natural gas properties completed in 2016 and 2017. Depreciation, depletion, amortization and accretion expense per Mcfe was $1.28, $0.72, and $0.95 for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the year ended December 31, 2016 (Predecessor), respectively

Depletion expense is not comparable between the Successor and Predecessor periods as a result of our implementation of fresh-start accounting upon bankruptcy emergence whereupon the carrying value of our proved oil and gas properties on our balance sheet was recorded at fair value. The application of fresh start accounting resulted in an increase in the amortization base which led to a corresponding increase in the depletion rate per equivalent unit of production for the five months ended December 31, 2017. As previously discussed, upon emergence, we changed our method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting, which also resulted in a higher depletion rate per equivalent unit of production. We adjust our depletion rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs. Thus, our depletion rate could change significantly in the future.

An impairment of oil and natural gas properties of $47.6 million was recognized during the five months ended December 31, 2017 (Successor) as a result of a downward revision of estimated proved reserves at the measurement date of December 31, 2017. The impairment charge is related to the reduced value of certain of our operating districts resulting from lower forward prices and a faster than expected decline of reserves primarily due to management’s decision to focus capital in key strategic areas with significant future development potential, rather than in areas with little upside.

Selling, general and administrative expenses include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. During the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the year ended December 31, 2016 (Predecessor), selling, general and administrative expenses were $21.6 million, $23.0 million and $41.3 million, respectively. General and administrative expenses in 2017 have been impacted by costs incurred in connection with the Chapter 11 Cases.

In addition, we incurred non-cash compensation expense of $0.1 million, $5.8 million and $10.2 million for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the year ended December 31, 2016 (Predecessor), respectively. Pursuant to the Final Plan, all unvested equity grants under the Predecessor’s Long-Term Incentive Plan (the “Predecessor Incentive Plan”) that were outstanding immediately before the Effective Date were canceled and of no further force or effect as of the Effective Date. In addition, on the Effective Date, the Predecessor’s Incentive Plan was canceled and extinguished, and participants in the Predecessor’s Incentive Plan received no payment or other distribution on account of the Incentive Plan. See Note 12 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, for further discussion about the Successor Management Incentive Plan.

Other Income and Expense

Interest expense was $24.2 million, $35.3 million and $95.4 million during the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017 (Predecessor) and the year ended December 31, 2016 (Predecessor), respectively. The Successor has lower interest expense due to lower debt outstanding. The decrease in interest expense during the Predecessor period was primarily due to the discontinuance of interest on its senior notes that were canceled as part of its Chapter 11 Cases.

During the five months ended December 31, 2017 (Successor), the Company recorded a net gain of approximately $4.5 million on the sale of oil and natural gas properties.

Reorganization Items

We incurred reorganization costs of $6.5 million during the five months ended December 31, 2017 (Successor) and a reorganization gain of $908.5 million for the seven months ended July 31, 2017 (Predecessor). The Predecessor gain resulted from the gain on the discharge of debt and fresh-start adjustments upon emergence from Chapter 11 bankruptcy. See Note 3 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for further details. We also recognized pre-petition costs of $3.2 million related to the Chapter 11 Cases in 2016.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 (Predecessor)

Revenues

Oil, natural gas and NGLs sales decreased by $8.5 million, or 2%, to $388.7 million during the year ended December 31, 2016 as compared to the same period in 2015. The key revenue measurements were as follows:



	Year Ended December 31,⁽¹⁾				Percentage Increase (Decrease)
	2016		2015		Percentage Increase (Decrease)
Average realized prices, excluding hedging:
Oil (Price/Bbl)	$	36.47	$	40.94	(11	)%
Natural Gas (Price/Mcf)	$	1.61	$	1.81	(11	)%
NGLs (Price/Bbl)	$	11.97	$	11.35	5	%

Average realized prices, including hedging ⁽²⁾:
Oil (Price/Bbl)	$	53.20	$	56.89	(6	)%
Natural Gas (Price/Mcf)	$	2.95	$	3.13	(6	)%
NGLs (Price/Bbl)	$	13.19	$	13.68	(4	)%

Average NYMEX prices:
Oil (Price/Bbl)	$	42.68	$	47.79	(11	)%
Natural Gas (Price/Mcf)	$	2.44	$	2.64	(8	)%

Total production volumes:
Oil (MBbls)	4,660		4,008		16	%
Natural Gas (MMcf)	108,107		106,615		1	%
NGLs (MBbls)	3,716		3,489		6	%
Combined (MMcfe)	158,359		151,600		4	%

Average daily production volumes:
Oil (Bbls/day)	12,731		10,982		16	%
Natural Gas (Mcf/day)	295,374		292,095		1	%
NGLs (Bbls/day)	10,153		9,560		6	%
Combined (Mcfe/day)	432,676		415,343		4	%


(1)	During 2016 and 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward.


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

The decrease in oil, natural gas and NGLs sales during the year ended December 31, 2016 compared to the same period in 2015 was primarily due to the decrease in the average realized oil and natural gas prices. The decrease in prices was partially offset by an overall increase in oil, natural gas and NGLs volumes primarily attributable to the oil and natural gas properties acquired in the LRE Merger and the Eagle Rock Merger completed during fourth quarter of 2015.

Natural gas revenues decreased by 10% from $193.5 million during the year ended December 31, 2015 to $174.3 million during the same period in 2016 primarily as a result of a $0.20 per Mcf, or 11%, decrease in our average realized natural gas sales price received, excluding hedges. The decrease in average realized natural gas price is primarily due to a lower average NYMEX price, which decreased from $2.64 per Mcf during the year ended December 31, 2015 to $2.44 per Mcf during the same period in 2016. The impact of the decrease in average realized price was partially offset by a 1,492 MMcf increase in our natural gas production volumes attributable to the LRE and Eagle Rock Mergers completed during the fourth quarter of 2015.

NGLs revenues increased by 12% in 2016 compared to the same period in 2015 due a 227 MBbls, or 7%, increase in NGLs production volumes and a $0.62 per Bbl, or 5%, increase in our average realized NGLs sale price received, excluding hedges.

Oil revenues increased by 4% from $164.1 million during the year ended December 31, 2015 to $170.0 million during the same period in 2016 as a result of a 652 MBbls, or 16%, increase in oil production volumes in 2016 compared to the prior year principally due to the positive impact of our acquisitions and the LRE and Eagle Rock Mergers. The impact of the increase in oil production volumes was partially offset by a $4.47 per Bbl, or 11%, decrease in our average realized oil sales price received, excluding hedges. The decrease in average realized oil price is primarily due to a lower average NYMEX price, which decreased from $47.79 per Bbl during the year ended December 31, 2015 to $42.68 per Bbl during the same period in 2016.

Overall, our total production increased by 4% on a Mcfe basis for the year ended December 31, 2016 over the comparable period in 2015. On a Mcfe basis, crude oil, natural gas and NGLs accounted for 18%, 68% and 14%, respectively, of our production during the year ended December 31, 2016 compared to crude oil, natural gas and NGLs of 16%, 70% and 14%, respectively, during the same period in 2015.

Hedging and Price Risk Management Activities

During the year ended December 31, 2016, we recognized a $44.1 million net loss on commodity derivative contracts. Net cash settlements on matured commodity derivative contracts of $226.9 million and proceeds from monetization of commodity derivative contracts of $54.0 million were received during the period. As of December 31, 2016, we had no commodity derivative contracts in place.

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by $13.0 million to $159.7 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015, of which $30.4 million is primarily attributable to additional expenses associated with oil and natural gas properties acquired in the LRE Merger and the Eagle Rock Merger. The increase was offset by a $17.4 million decrease 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 and county and are based on the value of our reserves. Production and other taxes decreased by $1.9 million to $38.6 million for the year ended December 31, 2016 primarily due to lower wellhead revenues as a result of the decrease in our average realized oil and natural gas prices. As a percentage of wellhead revenues, production, severance, and ad valorem taxes decreased from 10.2% during the year ended December 31, 2015 to 9.9% for the year ended December 31, 2016.

Depreciation, depletion, amortization and accretion decreased to approximately $149.8 million for the year ended December 31, 2016 from approximately $247.1 million for the year ended December 31, 2015 due to a decrease in the depletion base as a result of the non-cash ceiling impairment charges recorded during 2015 and 2016.

An impairment of oil and natural gas properties of $494.3 million was recognized during the year ended December 31, 2016 as a result of a decline in realized oil and natural gas prices at the respective measurement dates of March 31, 2016, June 30, 2016 and December 31, 2016. Such impairment was recognized during the first, second and fourth quarters of 2016 and calculated using the prices indicated above under “Recent Developments and Outlook.” The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2016 was the reduction in our proved reserves quantities due to the impact of lower commodity prices and uncertainties surrounding the availability of the financing that would be necessary to develop our proved undeveloped reserves.

We recorded a non-cash goodwill impairment loss of $252.7 million for the year ended December 31, 2016 to write the goodwill down to its estimated fair value of $253.4 million. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and natural gas properties include: (i) observable forward prices for commodities at December 31, 2016 and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on our evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

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 for the year ended December 31, 2016 increased by $4.8 million as compared to the year ended December 31, 2015 primarily resulting from approximately $13.6 million related to the hiring of additional employees, higher office expenses and professional services related to the LRE Merger and the Eagle Rock Merger completed in the fourth quarter of 2015, $3.2 million in pre-petition restructuring costs, $2.3 million in transaction fees incurred on divestitures and a $3.0 million increase in our bad debt provision on uncollectible accounts. This increase was partially offset by a decrease of about $11.3 million recognized in 2015 for the severance costs paid to former Eagle Rock executives and employees who were terminated subsequent to the Eagle Rock Merger, $3.2 million in Texas franchise tax and federal tax provision attributed to the increase in the deferred tax asset and decrease in the deferred tax liability associated with our oil and natural gas properties and a $2.9 million increase in COPAS overhead income attributed to the increase in operated wells acquired through the LRE Merger and the Eagle Rock Merger completed in the fourth quarter of 2015. Non-cash compensation expense for the year ended December 31, 2016 decreased $8.3 million to $10.2 million as compared to the year ended December 31, 2015, primarily related to the accelerated vesting of LTIP grants issued to former Eagle Rock executives and employees that are attributable to post merger services amounting to $7.3 million during 2015. In addition, during 2015, our board of directors approved the option for Vanguard’s management team to receive Vanguard common units in lieu of their 2015 cash compensation. Messrs. Smith and Robert and our three independent directors, Loren B. Singletary, W. Richard Anderson and Bruce W. McCullough elected this option and under the plan received quarterly grants of Vanguard common units instead of their 2015 cash compensation, resulting in higher non-cash compensation for the year ended December 31, 2015.

Other Income and Expense

Interest expense increased to $95.4 million for the year ended December 31, 2016 as compared to $87.6 million for the year ended December 31, 2015 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility and higher interest rates in 2016 compared to the same period in 2015. For the year ended December 31, 2016, we recorded a gain on extinguishment of debt amounting to $89.7 million which represents the difference between the aggregate fair market value the Senior Secured Second Lien Notes issued and the net carrying amount of Senior Notes due 2020 that were part of the Debt Exchange entered into in February 2016.

During the year ended December 31, 2016, Vanguard made adjustments to the amounts assigned to the net assets acquired related to the Eagle Rock Merger based on new information obtained about facts that existed as of the merger date. As a result, the bargain purchase gain was reduced by $5.0 million. This adjustment is included in the net loss on acquisition of oil and natural gas properties for this period.

In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at the acquisition date of the assets acquired in the acquisitions completed during 2015 compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $40.8 million and goodwill of $156.8 million, of which $0.3 million was immediately impaired and recorded as a loss, resulting in a net gain of $40.5 million for the year ended December 31, 2015. The net gains and losses resulted from the increases and decreases in oil and natural gas prices used to value the reserves between the commitment and close dates and have been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations included under Part II, Item 8 of this Annual Report.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.

Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We have discussed the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read Note 1 of the Notes to the Consolidated Financial Statements included in Part II, Item 8 of this Annual Report, for a discussion of additional accounting policies and estimates made by management.

Accounting Policies

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

•

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


•	We changed our method of accounting for natural gas and oil properties from the full cost method of accounting to the successful efforts method of accounting;


•	We adopted the new standard for revenue recognition under ASC Topic 606 upon emergence. The new guidance requires us to recognize revenue upon transfer of goods or services to a customer at an amount that reflects the expected consideration to be received in exchange for those goods or services; and


•	We changed from a pass-through entity for tax purposes to a C corporation and, accordingly, a taxable entity;

Fresh-Start Accounting

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

We adopted fresh-start accounting in accordance with the provisions set forth in ASC Topic 852 as (i) the fair value of the Successor Company’s total assets or the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to “Plan of Reorganization” above for the terms of our reorganization under the Final Plan. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Final Plan, our consolidated financial statements subsequent to July 31, 2017 are not comparable to our consolidated financial statements prior to July 31, 2017; as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Refer to Note 3 of the Notes to the Consolidated Financial Statements, included under Part II, Item 8 of this Annual Report, for more details.

Successor Oil and Natural Gas Properties

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

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

Upon emergence from bankruptcy, we adopted the successful efforts method of accounting for our oil and natural gas properties. We believe that application of successful efforts accounting will provide greater transparency in the results of our oil and natural gas properties and enhance decision making and capital allocation processes. Additionally, application of the successful efforts method will eliminate proved property impairments based on historical prices, which are not indicative of the fair value of our oil and natural gas properties, and better reflect the true economics of developing our oil and natural gas reserves. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties.

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

Depreciation, depletion and amortization

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

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are assessed for impairment in accordance with ASC Topic 360, Property, Plant and Equipment, when events and circumstances indicate a decline in the recoverability of the carrying values of such properties, such as a negative revision of reserves estimates or sustained decrease in commodity prices, but at least annually. We estimate future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the

properties to determine if the carrying amount is recoverable. If the sum of the undiscounted pretax cash flows is less than the carrying amount, then the carrying amount is written down to its estimated fair value.

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

During the five months ended December 31, 2017, the Company recorded an impairment of oil and natural gas properties of $47.6 million which primarily relates to the reduced value of certain of our operating districts resulting from lower forward prices and faster than expected decline of reserves primarily due to management’s decision to focus capital in key strategic areas with significant future development potential, rather than in areas with little upside.

Predecessor Oil and Natural Gas Properties

The Predecessor recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2016 of $494.3 million. Such impairment was recognized during the first, second and fourth quarters of 2016 and was calculated based on 12-month average prices for oil and natural gas as follows:



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2016	$	207,764	$2.41	$46.16
Second quarter 2016	$	157,894	$2.24	$42.91
Third quarter 2016	$	—	$2.29	$41.48
Fourth quarter 2016	$	128,612	$2.47	$42.60
Total	$	494,270

The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2016 were the reduction in our proved reserves quantities due to the reclassification of our proved undeveloped reserves to contingent resources due to uncertainties surrounding the availability of financing that would be necessary to develop these reserves and the impact of sustained lower commodity prices.

The Predecessor recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices. Such impairment was recorded during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows:



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2015	$	132,610	$3.91	$82.62
Second quarter 2015	$	733,365	$3.44	$71.51
Third quarter 2015	$	491,487	$3.11	$59.23
Fourth quarter 2015	$	484,855	$2.62	$50.20
Total	$	1,842,317

The most significant factors affecting the 2015 impairment were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisition dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because GAAP only allows the inclusion of derivatives designated as cash flow hedges.

Business Combinations

We account for business combinations under ASC Topic 805. We recognize and measure in our financial statements the fair value of all identifiable assets acquired, the liabilities assumed, any non-controlling interests in the acquiree and any goodwill acquired in all transactions in which control of one or more businesses is obtained.

Asset Retirement Obligation

We have obligations to remove tangible equipment and restore land at the end of an oil or natural gas well’s life. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and the decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Estimating the future plugging and abandonment costs requires management to make estimates and judgments inherent in the present value calculation of the future obligation. These include ultimate plugging and abandonment costs, inflation factors, credit adjusted discount rates, and timing of the obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

Oil, Natural Gas and NGLs Reserve Quantities

Our reservoir engineers estimate proved oil and gas reserves accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion, amortization and accretion. Proved oil and gas reserves are defined by the SEC as the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Although our reservoir engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation and depletion rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

Revenue Recognition

Impact of ASC Topic 606 Adoption

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

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



	Successor
	Five Months Ended December 31, 2017
	Under ASC 606			Under ASC 605			Increase
Revenues:
Oil sales	$	72,557		$	72,557		$	—
Natural gas sales	96,236			81,986			14,250
NGLs sales	36,825			31,873			4,952
Oil, natural gas and NGLs sales	205,618			186,416			19,202
Net losses on commodity derivative contracts	(55,857		)	(55,857		)	—
Total revenues and gains (losses) on derivatives	$	149,761		$	130,559		$	19,202
Costs and expenses:
Transportation, gathering, processing, and compression	$	19,202		$	—		$	19,202
Net loss	$	(111,278	)	$	(111,278	)	$	—

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

Revenue from Contracts with Customers

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

Natural gas and NGLs Sales

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

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

Oil sales

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


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

•

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

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC Topic 606, for the period from August 1, 2017 through December 31, 2017, there was no material impact to the financial statements due to this change in accounting for our production imbalances.

Transaction price allocated to remaining performance obligations

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

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

Contract balances

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

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period from August 1, 2017 through December 31, 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, our revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase without consideration of hedging. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded.

The Predecessor elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at 2016.

Price Risk Management Activities

We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Currently, we primarily use fixed-price swaps and collars to hedge oil, and natural gas and NGLs prices.

Under ASC Topic 815, Derivatives and Hedging (“ASC Topic 815”), the fair value of hedge contracts is recognized in the Consolidated Balance Sheets as an asset or liability, and since we do not apply hedge accounting, the change in fair value of the hedge contracts are reflected in earnings. If the hedge contracts qualify for hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income,” and changes in the fair value do not affect net income until the contract is settled. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as gain or loss on commodity derivatives.

Stock Based Compensation

We account for stock based compensation pursuant to ASC Topic 718, Compensation-Stock Compensation (“ASC Topic 718”). ASC Topic 718 requires an entity to recognize the estimated grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. It establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all companies to apply a fair-value-based measurement method in accounting for generally all share-based payment transactions with employees.

Recently Issued Accounting Pronouncements

Please read Note 1 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for a detailed list of recently issued accounting pronouncements.

Capital Resources and Liquidity

Overview

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

Statements of Cash Flows

Net increase (decrease) in cash is summarized as follows (in millions):



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Years Ended December 31,

							2016			2015
Net cash provided by operating activities	$	37.8		$	52.3		$	290.3		$	370.1
Net cash provided by (used in) used in investing activities	$	(29.5	)	$	76.8		$	206.8		$	(128.1	)
Net cash used in financing activities	$	(33.1	)	$	(151.5	)	$	(447.1	)	$	(241.9	)

Cash Flow from Operations

Net cash provided by operating activities for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor) were $37.8 million and $52.3 million, respectively. Net cash provided by operating activities for the years ended December 31, 2016 and 2015 (Predecessor) were $290.3 million and $370.1 million, respectively.

During the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), changes in working capital decreased total cash flows by $6.2 million and $1.6 million, respectively. Contributing to the decrease in working capital in each period was the decrease in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments. The increase in accounts receivable of $11.4 million for the five months ended December 31, 2017 (Successor) also contributed to the decrease in working capital while the decrease in accounts receivable of $34.8 million offset the decrease in working capital during the seven months ended July 31, 2017 (Predecessor).

During the year ended December 31, 2016 (Predecessor), changes in working capital decreased total cash flows by $40.0 million. Contributing to the decrease in working capital during 2016 was a $59.5 million decrease in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments and offset by a $9.6 million decrease in accounts receivable related to the timing of receipts from production.

During the year ended December 31, 2015 (Predecessor), changes in working capital increased cash flows by $18.9 million. Contributing to the increase in working capital during 2015 was a $53.4 million decrease in accounts receivable related to the timing of receipts from production from the acquisitions, offset by a $43.9 million decrease in accounts payable and oil and

natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice 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 in the periods ended 2017, 2016 and 2015.

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 and political activity, weather and other factors beyond our control. Future cash flow from operations will depend on our ability to maintain and increase production through our drilling program as well as the prices of oil, natural gas and NGLs. We entered into derivative contracts to reduce the impact of commodity price volatility on operations. During 2017, we primarily used fixed-price swaps and collars to hedge oil and natural gas prices. However, unlike natural gas, we are unable to hedge oil price differentials in certain operating areas which could significantly impact our cash flow from operations.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $29.5 million for the five months ended December 31, 2017 (Successor) and net cash provided in investing activities was $76.8 million for the seven months ended July 31, 2017 (Predecessor). Net cash provided in investing activities was $206.8 million during the year ended December 31, 2016 (Predecessor) compared to cash used of $128.1 million during the year ended December 31, 2015 (Predecessor).

During the five months ended December 31, 2017 (Successor), we spent $34.7 million on oil and natural gas capital expenditures and $31.0 million for deposits and prepayments related to the drilling and development of oil and natural gas offset by the proceeds from the sale of oil and natural gas properties of $36.1 million.

The primary source of net cash provided by investing activities was the proceeds from the sale of oil and natural gas properties of $126.4 million for the seven months ended July 31, 2017 (Predecessor). In addition, we spent $25.7 million on oil and natural gas capital expenditures and $23.7 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 year ended December 31, 2016 (Predecessor) primarily included $298.7 million in proceeds from the divestiture of certain oil and natural gas properties. Also during the year, cash used in investing activities included $64.5 million for the drilling and development of oil and natural gas properties, $19.7 million for deposits and prepayments related to the drilling and development of oil and natural gas properties and $7.5 million for the acquisition of a 51% joint venture interest in the Potato Hills Gas Gathering System.

During the year ended December 31, 2015 (Predecessor), we used cash of $112.6 million for the drilling and development of oil and natural gas properties, $22.2 million for deposits and prepayments related to the drilling and development of oil and natural gas properties, $13.0 million for the acquisition of oil and natural gas properties and $0.6 million for property and equipment additions. Also during the year, we received $18.5 million in cash when we closed the LRE and Eagle Rock Mergers and $1.8 million in proceeds from the divestiture of certain oil and natural gas properties.

The Board approved an initial capital expenditures budget for 2018 of $160.0 million compared to the $63.8 million and $46.1 million we spent during the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Our initial 2018 capital expenditures budget includes approximately $135.0 million of drilling and completion capital, or 85% of the total capital budget. More than 97% of the drilling and completion capital is focused on the core growth assets of Green River, Piceance and Arkoma Basins. We expect to spend between $90.0 million to $95.0 million or approximately 69% of the drilling capital budget in the Green River Basin at the Pinedale field where we will participate as a non-operated partner in the drilling and completion of vertical and horizontal wells. Additionally, we expect to spend between $20.0 million to $26.0 million or approximately 15% of the drilling capital budget in the Piceance Basin, at the Mamm Creek field where we will operate a one rig program drilling and completing vertical gas wells. We also expect to spend approximately 13% of our budgeted drilling capital in the Arkoma Basin in Oklahoma where we will be participating as a non-operated partner with Newfield and BP in a one rig program drilling and completing horizontal Woodford wells. The remaining drilling and completion capital will be spent on additional drilling, completion and production uplift projects in the Permian, Big Horn, and Powder River Basins.

We anticipate that our cash flow from operations, expected dispositions of oil and natural gas properties or asset sales as allowed under our credit agreements will exceed our planned capital expenditures and other cash requirements for the year ended

December 31, 2018. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $33.1 million and $151.5 million for the five months ended December 31, 2017 (Successor) and the seven months ended July 31, 2017 (Predecessor), respectively. Net cash used in financing activities was approximately $447.1 million and $241.9 million for the years ended December 31, 2016 and 2015 (Predecessor), respectively.

Cash used in financing activities during the five months ended December 31, 2017 (Successor) included $42.1 million for repayments of debt offset by proceeds of $9.8 million from borrowings under the Successor Credit Facility.

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

Net cash used in financing activities during the year ended December 31, 2016 (Predecessor) included cash of $517.2 million that was used in the repayments of the Predecessor Credit Facility and $4.2 million was paid for financing. We also paid distributions of $11.9 million to our common and Class B unitholders and $6.7 million to our preferred unitholders. Additionally, we received net proceeds from borrowings of long-term debt of $93.5 million.

Net cash used in financing activities during the year ended December 31, 2015 (Predecessor) included cash of $508.6 million that was used in the repayments of the Predecessor Credit Facility, $2.4 million was used for the repurchase of common units under the buyback program and $12.1 million was paid for financing costs and offering costs. We also paid $147.6 million in distributions to our common and Class B unitholders and $26.8 million in distributions to our preferred unitholders. Additionally, we received net proceeds from borrowings of long-term debt of $420.0 million and net proceeds from our common unit offerings of $35.5 million.

Debt and Credit Facilities

Successor Credit Facility

On the Effective Date, VNG, as borrower, has entered into the Successor Credit Facility, by and among VNG as borrower, the Administrative Agent and Issuing Bank, and the Lenders. Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with the Revolving Loans. The initial borrowing base available under the Successor Credit Facility as of the Effective Date is $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date was $730.0 million. The Successor Credit Facility also includes the Term Loan. The next borrowing base redetermination is scheduled for August of 2018.

On December 21, 2017, the borrowing base was reduced to $825.0 million following the completion of the Williston Divestiture. At December 31, 2017, there were $700.0 million of outstanding borrowings and $125.0 million of borrowing capacity under the Successor Credit Facility.

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

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

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

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



Year	Required Payments
2018	$	1,250
2019	1,250
2020	1,250
2021 through Maturity Dates	120,938

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

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

The Successor Credit Facility contains certain customary representations and warranties, including, without limitation: organization; powers; authority; enforceability; approvals; no conflicts; financial condition; no material adverse change; litigation; environmental matters; compliance with laws and agreements; no defaults; 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; anti-corruption laws and sanctions; and security instruments.

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

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

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

Senior Notes due 2024

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

The obligations under the Senior Notes due 2024 are guaranteed by all of the Company’s subsidiaries (“Second Lien Guarantors”) subject to limited exceptions, and secured on a second-priority basis by substantially all of the Company’s and the Second Lien Guarantors’ assets, including, without limitation, liens on the total value of the Company’s and the Second Lien Guarantors’ oil and gas properties, and pledges of stock of all other direct and indirect subsidiaries of the Company, subject to certain limited exceptions.

The New Notes are governed by an Amended and Restated Indenture, dated as of August 1, 2017 (as amended, the “Amended and Restated Indenture”), by and among the Company, certain subsidiary guarantors of the Company (the “Guarantors”) and Delaware Trust Company, as Trustee (in such capacity, the “Trustee”) and as Collateral Trustee (in such capacity, the “Collateral Trustee”), which contains 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 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. 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 certain equity offerings, 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, if any, to the redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:



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

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

Amended and Restated Intercreditor Agreement

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

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

Amended and Restated Collateral Trust Agreement

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

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

On the Effective Date, pursuant to the terms of the Final Plan, all outstanding obligations under the Predecessor’s Credit Facility, Old Second Lien Notes and unsecured senior notes were canceled. See Note 2 to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report, for additional information.

Predecessor Covenant Violations

The Company’s filing of the Bankruptcy Petitions described in Note 2 to the Consolidated Financial Statements, included under Part II, Item 8 of this Annual Report, constituted an event of default that accelerated the obligations under the Predecessor’s Credit Facility, Old Second Lien Notes and Senior Notes. For the period from February 1, 2017 to the Effective Date, contractual interest, which was not recorded, on the Senior Notes was approximately $17.2 million. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.

Lease Financing Obligations

On October 24, 2014, in connection with our acquisition of the Piceance Basin properties, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the 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 then current fair market value. The Lease Financing Obligations also contain an early buyout option where 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

We have no guarantees or off-balance sheet debt to third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.

Contingencies

The Company regularly analyzes current information and accrues 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. As of December 31, 2017, there were no material loss contingencies.

Commitments and Contractual Obligations

A summary of our contractual obligations as of December 31, 2017 is provided in the following table:



	Payments Due by Year (in thousands)
	2018		2019		2020		2021		2022		Thereafter		Total
Management base salaries	$	1,670	$	510	$	510	$	—	$	—	$	—	$	2,690
Asset retirement obligations ⁽¹⁾	5,707		4,700		4,935		5,182		5,441		131,459		157,424
Derivative liabilities	49,846		18,810		11,045		—		—		—		79,701
Successor Credit Facility ⁽²⁾	—		—		—		700,000		—		—		700,000
Term Loan ⁽²⁾	1,250		1,250		1,250		120,938		—		—		124,688
Senior Notes due 2024 and interest	7,265		7,265		7,265		7,265		7,265		92,205		128,530
Operating leases	1,202		1,149		1,135		1,169		1,204		4,504		10,363
Development commitments ⁽³⁾	25,274		—		—		—		—		—		25,274
Firm transportation and processing agreements⁽⁴⁾	1,009		820		410		—		—		—		2,239
Lease Financing Obligations ⁽⁵⁾	5,442		5,442		4,359		1,278		—		—		16,521
Other future obligations	468		308		—		—		—		—		776
Total	$	99,133	$	40,254	$	30,909	$	835,832	$	13,910	$	228,168	$	1,248,206


(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 9 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report for additional information regarding our asset retirement obligations.


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


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


(4)	Represents transportation demand charges. Please read Note 10 of the Notes to the Consolidated Financial Statements included under Part II, Item 8 of this Annual Report.


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

ITEM 7A. 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 overhedged volumes.

Commodity Price Risk

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

We routinely enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions in order to 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. Substantially all of our natural gas hedges are at regional sales points in our operating regions, which mitigate the risk of basis differential to the Henry Hub index. Typically, management intends to hedge 75% to 90% of projected oil and natural gas proved developed 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 NGLs hedging market is constrained in terms of price, volume, tenor and number of counterparties, which limits our ability to hedge our NGLs 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 we believe that we can take advantage of an unusual market condition allowing us to realize a current gain and then have the ability to enter into a new derivative contract in the future at or above the commodity price of the contract that was liquidated.

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

At December 31, 2017, the fair value of commodity derivative contracts was a liability of approximately $64.4 million of which $39.2 million settles during the next twelve months.

The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at December 31, 2017.



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



	Year 2018		Year 2019		Year 2020
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls)	2,712,450		1,858,200		1,393,800
Fixed Price ($/Bbl)	$	46.59	$	48.50	$	49.53
Collars:
Notional Volume (Bbls)	—		575,730		659,340
Floor Price ($/Bbl)	$	—	$	43.81	$	44.17
Ceiling Price ($/Bbl)	$	—	$	54.04	$	55.00



	Year 2018
NGLs Positions:
Fixed-Price Swaps:
Mont Belvieu Ethane
Notional Volume (Gallons)	9,198,000
Fixed Price ($/Gallon)	$	0.28
Mont Belvieu Propane
Notional Volume (Gallons)	22,995,000
Fixed Price ($/Bbl)	$	0.53
Mont Belvieu N. Butane
Notional Volume (Gallons)	7,665,000
Fixed Price ($/Gallon)	$	0.65
Mont Belvieu Isobutane
Notional Volume (Gallons)	6,132,000
Fixed Price ($/Gallon)	$	0.65
Mont Belvieu N. Gasoline
Notional Volume (Gallons)	10,731,000
Fixed Price ($/Gallon)	$	0.99

Interest Rate Risks

At December 31, 2017, we had debt outstanding of $912.0 million. The amount outstanding under our Successor Credit Facility at December 31, 2017 of $824.7 million 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 $1.2 million increase in annual interest expense. We also had $80.7 million aggregate principal amount of Senior Notes due 2024 outstanding and $15.2 million aggregate principal amount of Lease Financing Obligations with an implied interest rate of 4.16%.

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 (losses) on interest rate derivative contracts. At December 31, 2017, the Company had no outstanding interest rate hedge agreements.

Counterparty Risk

At December 31, 2017, based upon all of our open derivative contracts shown above and their respective mark to market values, we had the following current and long-term derivative liabilities shown by counterparty with their current Standard & Poor’s financial strength rating in parentheses (in thousands):



	Current Assets		Long-Term Assets		Current Liabilities			Long-Term Liabilities			Total Amount Due From/(Owed To) Counterparty at December 31, 2017
ABN AMRO Bank (A)	$	—	$	—	$	(25,816	)	$	(5,643	)	$	(31,459	)
Capital One (BBB+)	1,239		—		—			(5,234		)	(3,995		)
Citibank (A+)	—		—		(13,396		)	(4,574		)	(17,970		)
Huntington Bank (BBB+)	20		—		—			(9,384		)	(9,364		)
JP Morgan (A-)	999		—		—			(2,648		)	(1,649		)
Total	$	2,258	$	—	$	(39,212	)	$	(27,483	)	$	(64,437	)

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 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

Below is an index to the items contained in this “Item 8. Financial Statements and Supplementary Data.”



			Page
	Report of Independent Registered Public Accounting Firm		89
	Consolidated Statements of Operations		90
	Consolidated Balance Sheets		91
	Consolidated Statements of Equity		92
	Consolidated Statements of Cash Flows		93
	Notes to Consolidated Financial Statements		95
	Supplemental Financial Information
	Supplemental Selected Quarterly Financial Information (Unaudited)		137
	Supplemental Oil and Natural Gas Information		139

All schedules are omitted as the required information is not applicable or the information is presented in the Consolidated Financial Statements and related notes.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Vanguard Natural Resources, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Vanguard Natural Resources, Inc. (“Successor,” formerly Vanguard Natural Resources, LLC (“Predecessor”)) and subsidiaries as of December 31, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, stockholders’ equity, and cash flows for the period from August 1, 2017 through December 31, 2017 (Successor) and from January 1, 2017 through July 31, 2017 and for each of the two years in the period ended December 31, 2016 (Predecessor) and the related notes (collectively referred to as the “consolidated financial statements”). Successor and Predecessor are collectively referred to as the “Company.” In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at December 31, 2017 (Successor) and 2016 (Predecessor), and the results of their operations and their cash flows for the period from August 1, 2017 through December 31, 2017 (Successor) and from January 1, 2017 through July 31, 2017 and for each of the two years in the period ended December 31, 2016 (Predecessor), in conformity with accounting principles generally accepted in the United States of America.

Change in Basis of Accounting

As discussed in Note 3 to the consolidated financial statements, upon emerging from bankruptcy proceedings on August 1, 2017, the Company became a new entity for financial reporting purposes and applied fresh-start accounting. The Company’s assets and liabilities were recorded at their estimated fair values, which differed materially from the previously recorded amounts. As a result, the consolidated financial statements for the period following the application of fresh-start accounting are not comparable to the financial statements for previous periods.

Changes in Accounting Principles

As discussed in Note 4 to the consolidated financial statements, the Company changed its method of accounting for revenue recognition for the period from August 1, 2017 through December 31, 2017 (Successor) due to the adoption of Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606).

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for its oil and natural gas properties from the full cost method to the successful efforts method for the period from August 1, 2017 through December 31, 2017 (Successor).

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2008.

Houston, Texas

March 21, 2018

Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands, except per share/unit data)



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Years Ended December 31,
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			2016			2015
Revenues:
Oil sales	$	72,557		$	97,496		$	169,955		$	164,111
Natural gas sales	96,236			113,587			174,263			193,496
Natural gas liquids sales	36,825			35,565			44,462			39,620
Oil, natural gas and NGLs sales	205,618			246,648			388,680			397,227
Net gains (losses) on commodity derivative contracts	(55,857		)	(24,887		)	(44,072		)	169,416
Total revenues and gains (losses) on derivatives	149,761			221,761			344,608			566,643
Costs and expenses:
Production:
Lease operating expenses	60,976			87,092			159,672			146,654
Transportation, gathering, processing and compression	19,202			—			—			—
Production and other taxes	13,145			21,186			38,637			40,576
Depreciation, depletion, amortization and accretion	71,321			58,384			149,790			247,119
Impairment of oil and natural gas properties	47,640			—			494,270			1,842,317
Impairment of goodwill	—			—			252,676			71,425
Exploration expense	1,365			—			—			—
Selling, general and administrative expenses	21,658			28,810			51,518			55,076
Total costs and expenses	235,307			195,472			1,146,563			2,403,167
Income (loss) from operations	(85,546		)	26,289			(801,955		)	(1,836,524		)
Other income (expense):
Interest expense	(24,204		)	(35,276		)	(95,367		)	(87,573		)
Net gains (losses) on interest rate derivative contracts	—			30			(2,867		)	153
Net gain (loss) on acquisitions and divestiture of oil and natural gas properties	4,450			—			(4,979		)	40,533
Gain on extinguishment of debt	—			—			89,714			—
Other	510			783			447			237
Total other expense	(19,244		)	(34,463		)	(13,052		)	(46,650		)
Loss before reorganization items	(104,790		)	(8,174		)	(815,007		)	(1,883,174		)
Reorganization items	(6,488		)	908,485			—			—
Net income (loss)	(111,278		)	900,311			(815,007		)	(1,883,174		)
Less: Net income attributable to non-controlling interests	(132		)	(13		)	(82		)	—
Net income (loss) attributable to Vanguard stockholders/unitholders	(111,410		)	900,298			(815,089		)	(1,883,174		)
Less: Distributions to Preferred unitholders	—			(2,230		)	(26,758		)	(26,759		)
Net income (loss) attributable to Common stockholders/Common and Class B unitholders	$	(111,410	)	$	898,068		$	(841,847	)	$	(1,909,933	)
Net income (loss) per Share/Unit:
Basic and diluted	$	(5.55	)	$	6.84		$	(6.41	)	$	(19.80	)
Weighted average shares/units outstanding:
Common shares/units – basic and diluted	20,059			130,962			130,903			96,048
Class B units – basic and diluted	—			420			420			420

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except share/unit data)



	Successor			Predecessor
	December 31, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	2,762		$	49,957
Trade accounts receivable, net	67,248			97,138
Derivative assets	2,258			—
Restricted cash	7,255			—
Other currents assets	3,934			7,944
Total current assets	83,457			155,039
Oil and natural gas properties
Proved properties	1,560,552			4,725,692
Unproved Properties	85,393			—
	1,645,945			4,725,692
Accumulated depletion, amortization and impairment	(112,553		)	(3,867,439		)
Oil and natural gas properties evaluated, net – successful efforts method at December 31, 2017 and full cost method at December 31, 2016	1,533,392			858,253
Other assets
Goodwill	—			253,370
Other assets	26,671			42,626
Total assets	$	1,643,520		$	1,309,288
Liabilities and equity (deficit)
Current liabilities
Accounts payable:
Trade	$	9,141		$	12,929
Affiliates	—			1,443
Accrued liabilities:
Lease operating	13,560			14,909
Developmental capital	12,275			6,676
Interest	6,312			13,345
Production and other taxes	20,982			32,663
Other	9,005			5,416
Derivative liabilities	39,212			125
Oil and natural gas revenue payable	37,422			33,672
Long-term debt classified as current	—			1,753,345
Other current liabilities	12,175			14,160
Total current liabilities	160,084			1,888,683
Long-term debt	905,976			15,475
Derivative liabilities	27,483			—
Asset retirement obligations	151,717			264,552
Other long-term liabilities	732			39,443
Total liabilities	1,245,992			2,208,153
Commitments and contingencies (Note 10)

Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Balance Sheets - Continued

(in thousands, except share/unit data)



	Successor			Predecessor
	December 31, 2017			December 31, 2016
Stockholders’ equity/members’ deficit (Note 11)
Predecessor Preferred units, no units issued or outstanding at December 31, 2017; 13,881,873 units issued and outstanding at December 31, 2016	—			335,444
Predecessor Common units, no units issued or outstanding at December 31, 2017; 131,008,670 units issued and outstanding at December 31, 2016	—			(1,248,767		)
Predecessor Class B units, no units issued or outstanding at December 31, 2017; 420,000 issued and outstanding at December 31, 2016	—			7,615
Successor common stock ($0.001 par value, 50,000,000 shares authorized and 20,100,178 shares issued and outstanding at December 31, 2017; no shares authorized or issued at December 31, 2016	20			—
Successor additional paid-in capital	506,640			—
Successor accumulated deficit	(111,410		)	—
Total stockholders' equity/members’ deficit	395,250			(905,708		)
Non-controlling interest in subsidiary	2,278			6,843
Total stockholders' equity/members’ deficit	397,528			(898,865		)
Total liabilities and equity	$	1,643,520		$	1,309,288

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Statements of Members’ Equity (Deficit) (Predecessor)

For the Seven Month Period Ended July 31, 2017 and the Years Ended December 31, 2016 and 2015



(in thousands)	Cumulative Preferred Units			Common Units			Class B Units			Non-controlling Interest			Total Members’ Equity (Deficit)
Balance at January 1, 2015 (Predecessor)	$	335,444		$	1,191,057		$	7,615		$	—		$	1,534,116
Issuance of Common units as consideration for the Eagle Rock Merger, net of merger costs of $5,560	—			253,068			—			—			253,068
Issuance of Common units as consideration for the LRE Merger, net of merger costs of $3,961	—			119,315			—			—			119,315
Issuance of Common units, net of offering costs of $593	—			35,544			—			—			35,544
Repurchase of units under the common unit buyback program	—			(2,399		)	—			—			(2,399		)
Distributions to Preferred unitholders	—			(26,760		)	—			—			(26,760		)
Distributions to Common and Class B unitholders	—			(134,019		)	—			—			(134,019		)
Unit-based compensation	—			16,874			—			—			16,874
Net loss	—			(1,883,174		)	—			—			(1,883,174		)
Balance at December 31, 2015 (Predecessor)	335,444			(430,494		)	7,615			—			(87,435		)
Issuance costs related to prior period equity transactions	—			(250		)	—			—			(250		)
Distributions to Preferred unitholders	—			(5,575		)	—			—			(5,575		)
Distributions to Common and Class B unitholders	—			(7,998		)	—			—			(7,998		)
Unit-based compensation	—			10,639			—			—			10,639
Non-controlling interest in subsidiary	—			—			—			7,452			7,452
Net income (loss)	—			(815,089		)	—			82			(815,007		)
Potato Hills cash distribution to non-controlling interest	—			—			—			(691		)	(691		)
Balance at December 31, 2016 (Predecessor)	335,444			(1,248,767		)	7,615			6,843			(898,865		)
Issuance costs related to prior period equity transactions	—			19			—			—			19
Unit-based compensation	—			5,391			—			—			5,391
Net income	—			900,298			—			13			900,311
Potato Hills cash distribution to non-controlling interest	—			—			—			(235		)	(235		)
Balance at July 31, 2017 (Predecessor)	$	335,444		$	(343,059	)	$	7,615		$	6,621		$	6,621
Cancellation of Predecessor equity	(335,444		)	343,059			(7,615		)	(4,347		)	(4,347		)
Balance at July 31, 2017 (Predecessor)	$	—		$	—		$	—		$	2,274		$	2,274

Consolidated Statement of Stockholders’ Equity (Successor)

For the Five Month Period Ended December 31, 2017



	Common Stock
(in thousands, except per share amounts)	Shares	Amount		Additional Paid-in Capital			Accumulated Deficit			Non- controlling Interest			Total Stockholders' Equity
Issuance of Successor common stock and warrants	20,056	$	20	$	506,923		$	—		$	—		$	506,943
Balance at July 31, 2017 (Successor)	20,056	20		506,923			—			2,274			509,217
Net income (loss)	—	—		—			(111,410		)	132			(111,278		)
Exercise of warrants	—	—		12			—			—			12
Issuance of common shares for settlement of general unsecured claims	44	—		—			—			—			—
Offering costs	—	—		(376		)	—			—			(376		)
Share-based compensation	—	—		81			—			—			81
Potato Hills cash distribution to non-controlling interest	—	—		—			—			(128		)	(128		)
Balance at December 31, 2017 (Successor)	20,100	$	20	$	506,640		$	(111,410	)	$	2,278		$	397,528

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows



	Successor			Predecessor
(in thousands)	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Year Ended December 31, 2016			Year Ended December 31, 2015
Operating activities
Net income (loss)	$	(111,278	)	$	900,311		$	(815,007	)	$	(1,883,174	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	71,321			58,384			149,790			247,119
Impairment of oil and natural gas properties	47,640			—			494,270			1,842,317
Impairment of goodwill	—			—			252,676			71,425
Amortization of deferred financing costs	1,117			2,584			4,565			4,206
Amortization of debt discount	—			348			3,746			1,071
Reorganization cost	—			(937,956		)	—			—
Compensation related items	81			5,429			10,639			16,874
Post Eagle Rock Merger severance costs	—			—			—			13,955
Net (gains) losses on commodity and interest rate derivative contracts	55,857			24,858			46,939			(169,569		)
Net cash settlements received (paid) on matured commodity derivative contracts	(12,174		)	7			226,876			211,723
Net cash settlements paid on matured interest rate derivative contracts	—			(95		)	(13,398		)	(5,227		)
Cash received on termination of derivative contracts	(4,140		)	—			53,955			40,998
Net (gain) loss on acquisitions and divestiture of oil and natural gas properties	(4,450		)	—			4,979			(40,533		)
Gain on extinguishment of debt	—			—			(89,714		)	—
Changes in operating assets and liabilities:
Trade accounts receivable	(11,381		)	34,845			9,559			53,423
Payables to affiliates	—			(895		)	(314		)	934
Premiums paid on commodity derivative contracts	—			(16		)	(430		)	(4,235		)
Restricted cash	—			(28,455		)	—			—
Other current assets	552			1,435			(3,050		)	(1,615		)
Accounts payable and oil and natural gas revenue payable	(138		)	19,444			(17,954		)	(555		)
Accrued expenses and other current liabilities	3,830			(27,018		)	(41,582		)	(43,320		)
Other assets	945			(922		)	13,735			14,267
Net cash provided by operating activities	37,782			52,288			290,280			370,084
Investing activities
Additions to property and equipment	(4		)	(102		)	(101		)	(644		)
Potato Hills Gas Gathering System acquisition	—			—			(7,501		)	—
Additions to oil and natural gas properties	(34,675		)	(25,694		)	(64,537		)	(112,639		)
Acquisitions of oil and natural gas properties and derivative contracts	—			—			—			(12,970		)
Cash acquired in the LRE and Eagle Rock Mergers	—			—			—			18,503
Proceeds from the sale of oil and natural gas properties	36,109			126,363			298,701			1,777
Deposits and prepayments of oil and natural gas properties	(30,956		)	(23,731		)	(19,740		)	(22,171		)
Net cash provided by (used in) investing activities	(29,526		)	76,836			206,822			(128,144		)
Financing activities
Proceeds from long-term debt	9,821			—			93,500			420,000
Repayment of debt	(42,118		)	(41,603		)	(517,157		)	(508,617		)
Proceeds from Term Loan borrowings	—			125,000			—			—
Repayment of debt under the predecessor credit facility	—			(500,266		)	—			—
Proceeds from common unit offerings, net	—			—			—			35,544
Proceeds from rights offerings and second lien investment	—			275,000			—			—
Exercise of warrants	12			—			—			—
Repurchase of units under the common unit buyback program	—			—			—			(2,399		)
Distributions to Preferred unitholders	—			—			(6,690		)	(26,760		)
Distributions to Common and Class B members	—			—			(11,902		)	(147,641		)
Potato Hills distribution to non-controlling interest	(128		)	(235		)	(691		)	—
Financing fees	(691		)	(9,367		)	(4,205		)	(12,067		)
Net cash used in financing activities	(33,104		)	(151,471		)	(447,145		)	(241,940		)



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Year Ended December 31, 2016		Year Ended December 31, 2015
Net increase (decrease) in cash and cash equivalents	(24,848		)	(22,347		)	49,957		—
Cash and cash equivalents, beginning of period	27,610			49,957			—		—
Cash and cash equivalents, end of period	$	2,762		$	27,610		$	49,957	$	—
Supplemental cash flow information:
Cash paid for interest	$	16,763		$	29,631		$	85,371	$	83,557
Non-cash financing and investing activities:
Asset retirement obligations	$	14,158		$	9,581		$	8,935	$	24,766
LRE and Eagle Rock Mergers
Assets acquired:
Accounts receivable and other current assets	$	—		$	—		$	—	$	44,201
Net derivative assets	$	—		$	—		$	—	$	166,758
Oil and natural gas properties	$	—		$	—		$	—	$	672,178
Other long-term assets	$	—		$	—		$	—	$	10,001
Liabilities assumed:
Accounts payable and other current liabilities	$	—		$	—		$	—	$	70,085
Asset retirement obligations	$	—		$	—		$	—	$	88,228
Long-term debt	$	—		$	—		$	—	$	446,550
Other long-term liabilities	$	—		$	—		$	—	$	40,571
Common units issued in the LRE and Eagle Rock Mergers	$	—		$	—		$	—	$	381,904

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2017

Description of the Business:

Vanguard Natural Resources, Inc. is an exploration and production company engaged in the production and development of oil and natural gas properties in the United States. The Company is currently focused on adding value by efficiently operating our producing assets and, in certain areas, applying modern drilling and completion technologies in order to fully assess and realize potential development upside. Our primary business objective is to increase shareholder value by growing reserves, production and cash flow in a capital efficient manner. Through our operating subsidiaries, as of December 31, 2017, we own properties and oil and natural gas reserves primarily located in nine operating basins:


•	the Green River Basin in Wyoming;


•	the Permian Basin in West Texas and New Mexico;


•	the Piceance Basin in Colorado;


•	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 Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

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

1. Summary of Significant Accounting Policies


(a)	Basis of Presentation and Principles of Consolidation:

Our consolidated financial statements are prepared in accordance with U.S. GAAP and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity.

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)	Emergence from Voluntary Reorganization under Chapter 11:

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

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

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


(c)	New Pronouncements Recently Adopted:

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

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

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

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


(d)	New Pronouncements Issued But Not Yet Adopted:

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” (“ASU No. 2016-02”), which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU No. 2016-02 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be adopted using a modified retrospective approach. We are currently evaluating the provisions of ASU 2016-02 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have allocated resources to the implementation and have begun contract and lease identification and review.

In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash” which is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the consolidated balance sheets to cash, cash equivalents and restricted cash on the consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU No. 2017-01”). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as a business combination. The ASU No. 2017-01 will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and should be applied prospectively. The Company is currently evaluating the provisions of ASU 2017-01 and assessing the impact adoption may have on our consolidated financial statements. Currently, we do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements; however these amendments could result in the recording of fewer business combinations in future periods.


(e)	Cash Equivalents:

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.


(f)	Accounts Receivable and Allowance for Doubtful Accounts:

Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.


(g)	Inventory:

Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets.


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

Successor Oil and Natural Gas Properties

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

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

Because a new entity has been created at the Effective Date, and the Successor’s financial statements are not comparable to the Predecessor’s financial statements (refer to Note 3, “Fresh-Start Accounting”), upon emergence from bankruptcy, we adopted the successful efforts method of accounting for our oil and natural gas properties. We believe that application of successful efforts accounting will provide greater transparency in the results of our oil and natural gas properties and enhance decision making and capital allocation processes. Additionally, application of the successful efforts method will eliminate proved property impairments based on historical prices, which are not indicative of the fair value of our oil and natural gas properties, and better reflect the true economics of developing our oil and natural gas reserves. Therefore, from August 1, 2017 we have used the successful efforts method to account for our investment in oil and natural gas properties in the Successor.

Depreciation, depletion and amortization

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

Impairment of Oil and Natural Gas Properties

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

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

During the five months ended December 31, 2017, the Company recorded impairment charges of $47.6 million which primarily relates to the reduced value of certain of our operating districts resulting from lower forward prices and faster than

expected decline of reserves primarily due to management’s decision to focus capital in key strategic areas with significant future development potential, rather than in areas with little upside.

Predecessor Oil and Natural Gas Properties



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2016	$	207,764	$2.41	$46.16
Second quarter 2016	$	157,894	$2.24	$42.91
Third quarter 2016	$	—	$2.29	$41.48
Fourth quarter 2016	$	128,612	$2.47	$42.60
Total	$	494,270



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2015	$	132,610	$3.91	$82.62
Second quarter 2015	$	733,365	$3.44	$71.51
Third quarter 2015	$	491,487	$3.11	$59.23
Fourth quarter 2015	$	484,855	$2.62	$50.20
Total	$	1,842,317


(i)	Goodwill and Other Intangible Assets:

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

In January 2017, the FASB issued ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment” (ASC 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 became 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. The Predecessor elected to early adopt ASU 2017-04 for the quarter ended March 31, 2017. The Predecessor did not record any goodwill impairment during the seven months ended July 31, 2017 since the carrying value of our reporting unit was negative at the measurement date. The balance of goodwill was eliminated upon the application of fresh start accounting.

Prior to the implementation of ASU 2017-04, the Predecessor performed annual impairment tests during 2016 and 2015 and concluded that there was no impairment of goodwill as of these dates. However, due to the decline in the prices of oil and natural gas as well as deteriorating market conditions, we also performed interim impairment tests at each quarter end. At each measurement date, if the Predecessor was required to perform the second step of the goodwill impairment test, the fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties included: (i) observable forward prices for commodities at the respective measurement date and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions.

As of December 31, 2015, the carrying value of our reporting unit was negative. Therefore the Predecessor was required to perform the second step of the goodwill impairment test. Based on the results of the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million. Based on evaluation of qualitative factors, we determined that the goodwill impairment was primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2017, the net carrying value of this contract was $2.2 million. The carrying value is shown as other assets on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.1 million per year.


(j)	Asset Retirement Obligations:

We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Big Escambia Creek, Elk Basin and Fairway gas plants. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.


(k)	Revenue Recognition and Gas Imbalances:

As discussed above, in conjunction with fresh-start accounting, the Company elected to early adopt the new revenue recognition standard effective August 1, 2017. See Note 4, “Impact of ASC 606 Adoption,” for further details related to the Company’s adoption of this standard.

100


(l)	Concentrations of Credit Risk:

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

At December 31, 2017 and 2016, the cash and cash equivalents were primarily concentrated in two and one financial institutions, respectively. We periodically assess the financial condition of the institutions and believe that any possible credit risk is minimal.

The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales during the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017, and the years ended December 31, 2016 and 2015 (Predecessor):



	Successor	Predecessor
	Five Months Ended December 31, 2017	Seven Months Ended July 31, 2017	2016	2015

ConocoPhillips	14%	13%	11%	7%
Mieco, Inc.	12%	11%	12%	20%

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.


(m)	Use of Estimates:

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


(n)	Price and Interest Rate Risk Management Activities:

We have entered into derivative contracts primarily with counterparties that are also lenders under the Successor Credit Facility (defined in Note 2) 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 overhedged volumes. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2017, our derivative transactions included the following:


•	Fixed-price swaps - where we 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.

Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings since specific hedge accounting criteria are not met. Gains or losses on derivative contracts are

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recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations.


(o)	Income Taxes:

Effective upon consummation of the Final Plan, the Successor became a C corporation subject to federal and state income taxes. As a C corporation, we account for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2017, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company incurred a net taxable loss in the current taxable period. Thus no current income taxes are anticipated to be paid and no net benefit will be recorded in the Company’s consolidated financial statements due to the full valuation allowance on the tax assets. Refer to Note 13 more information on the Company’s accounting for income taxes.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). In response, the SEC staff issued Staff Accounting Bulletin 118 (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC Topic 740, “Uncertain Tax Positions” (“ASC Topic 740”). In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC Topic 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. Refer to Note 13 more information on the Company’s accounting for income taxes.


(p)	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 Annual Report.

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

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

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Plan of Reorganization

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

•

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


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


•	The Predecessor’s Senior Notes were cancelled and the holders of the Senior Notes received their pro rata share of 97% (subject to dilution by the other transactions referred to in this section) of the Common Stock, in full and final satisfaction of their claims;

•


•	Additional shares of Common Stock, representing 10% of outstanding shares of Common Stock on a fully diluted basis, were authorized for issuance under the Vanguard Natural Resources, Inc. 2017 Management Incentive Plan (the “MIP”);


•	All outstanding Preferred Units (defined below) issued and outstanding immediately prior to the Effective Date were canceled and the holders thereof received their pro rata shares of (i) 3% (subject to dilution by the other transactions

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referred to in this section) of outstanding shares of Common Stock and (ii) Preferred Unit Warrants (as defined below), in full and final satisfaction of their interests;


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

•

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


•	By operation of the Final Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. A new board was established for the Successor Company;


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


•	The Successor issued 20.1 million shares of common stock, $0.001 par value.

Each of the foregoing percentages of equity in the Successor were as of August 1, 2017 and are subject to dilution from the exercise of the Warrants described above, the MIP discussed further in Note 11, “Stockholders’ Equity (Members’ Deficit),” and other future issuances of equity interests.

See Note 6, “Debt,” and Note 11, “Stockholders’ Equity (Members’ Deficit),” for further information regarding the Predecessor and Successor’s debt and equity instruments.

Listing on the OTCQX Market

3. Fresh-Start Accounting

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

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

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Reorganization Value is intended to represent the approximate amount a willing buyer would value the Company's assets immediately after the reorganization.

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

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

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

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

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

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

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



	July 31, 2017
Enterprise Value	$	1,425,000
Plus: Cash and cash equivalents	27,610
Less: Debt	(943,393		)
Total stockholders' equity	509,217
Less: Fair value of warrants	(11,734		)
Less: Fair value of non-controlling interest	(2,274		)
Fair Value of Successor common stock	$	495,209

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

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	July 31, 2017
Successor Credit Facility	$	730,000
Successor Term Loan	125,000
Senior Notes due 2024	80,722
Lease Financing Obligation, net of current portion	12,464
Current portion of Lease Financing Obligation	4,647
Total Fair value of debt	952,833
Successor Credit Facility fees and debt issuance costs	(9,440		)
Total Debt	$	943,393

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



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

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Condensed Consolidated Balance Sheet

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



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

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

Reorganization Adjustments:

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


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



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


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


4)	Net change to restricted cash includes the following:



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


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

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


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


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



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


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


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


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


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



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


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



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

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



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

See Note 11, “Stockholders’ Equity (Members’ Deficit)” for additional information on the issuances of the Successor’s equity.

Fresh-Start Adjustments:


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


16)	Reflects fair value adjustment for oil inventory.


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



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


18)	Reflects the write-off of Predecessor goodwill.


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



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

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

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approach was used to value the Company’s vehicles, using recent transactions of similar assets to determine the fair value from a market participant perspective.


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


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


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

23)

Primarily reflects the fair value adjustment of asset retirement obligations (“ARO”) to fair value of approximately $145.2 million, of which $136.8 million is reflected as long-term ARO and $8.4 million of current ARO shown in other current liabilities. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. Refer to Note 9, “Asset Retirement Obligations” for further details of the Company's asset retirement obligations.


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


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

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

Reorganization Items

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



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017
Gain on settlement of Liabilities subject to compromise	$	—		$	452,129
Fresh-start accounting adjustments	—			781,520
Issuance of common shares and warrants	—			(214,140		)
Legal and other professional fees	(6,488		)	(58,482		)
Recognition of additional unsecured claims	—			(31,346		)
Write-off of deferred financing costs and debt discounts	—			(21,361		)
Terminated contracts	—			165
Reorganization items	$	(6,488	)	$	908,485

4. Impact of ASC 606 Adoption

In conjunction with the application of fresh-start accounting, we adopted ASC 606 - Revenue from Contracts with Customers (“ASC 606”). We adopted using the modified retrospective method, which fresh-start accounting allows us to apply the new standard to all new contracts entered into after August 1, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of July 31, 2017. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services.

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

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	Successor
	Five Months Ended December 31, 2017
	Under ASC 606			Under ASC 605			Increase
Revenues:
Oil sales	$	72,557		$	72,557		$	—
Natural gas sales	96,236			81,986			14,250
NGLs sales	36,825			31,873			4,952
Oil, natural gas and NGLs sales	205,618			186,416			19,202
Net losses on commodity derivative contracts	(55,857		)	(55,857		)	—
Total revenues and gains (losses) on derivatives	$	149,761		$	130,559		$	19,202
Costs and expenses:
Transportation, gathering, processing, and compression	$	19,202		$	—		$	19,202
Net loss	$	(111,278	)	$	(111,278	)	$	—

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

Revenue from Contracts with Customers

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

Natural gas and NGLs Sales

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

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

Oil sales

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

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

•

Production imbalances

Previously, the Company elected to utilize the entitlements method to account for natural gas production imbalances which is no longer applicable. In conjunction with the adoption of ASC 606, for the period from August 1, 2017 through December 31, 2017, there was no material impact to the financial statements due to this change in accounting for our production imbalances.

Transaction price allocated to remaining performance obligations

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

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

Contract balances

Prior-period performance obligations

5. 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 prior to our emergence from bankruptcy were funded with borrowings under the Predecessor reserve-based credit facility, except for certain acquisitions, in which the Company issued shares or exchanged assets as described below.

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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 “Glasscock Divestiture”). The Glasscock Divestiture 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 Predecessor reserve-based credit facility on August 1, 2017, the Effective Date of the Final Plan.

In December 2017, we completed the sale of our oil and natural gas properties in the Williston Basin in North Dakota and Montana (“Williston Divestiture”) for a consideration of $36.9 million, subject to post-closing adjustments to be determined, and $5.0 million related to the relief of asset retirement obligations.

We also completed sales of certain of our other properties located in our various operating areas for an aggregate consideration of approximately $0.4 million and $23.7 million during the five months ended December 31, 2017 (Successor) and seven months ended July 31, 2017 (Predecessor), respectively.

The Glasscock Divestiture and the sale of other oil and natural properties that were completed prior to the Effective Date did not significantly alter the relationship between the Predecessor capitalized costs and proved reserves. As such, no gain or loss on sales of oil and natural were recognized and the sales proceeds were treated as a reduction to the carrying value of the Predecessor full cost pool.

As discussed under Note 1. Summary of Significant Accounting Policies, the Company elected to change its method of accounting for oil and gas exploration and development activities from the full cost method of accounting to the successful efforts method of accounting as of the Effective Date. Under the successful efforts method, costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. The Company recorded a gain of approximately $4.4 million from the Williston Divestiture, which is included in “Net gains (losses) on acquisitions and divestiture of oil and natural gas properties” in our consolidated statement of operations.

2016 Acquisition 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 assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $270.5 million (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 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 were recognized and the sales proceeds were treated as an adjustment to the cost of the properties.

2015 Acquisitions and Mergers

On July 31, 2015, we completed the acquisition of additional interests in the same properties located in the Pinedale field of Southwestern Wyoming that were previously acquired in the Pinedale Acquisition in 2014 for an adjusted purchase price of $11.4 million based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

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LRE Merger

On October 5, 2015, we completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among us, Lighthouse Merger Sub, LLC, our wholly owned subsidiary (“LRE Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C”), and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”), the general partner of LRE.

Pursuant to the terms of the LRE Merger Agreement, LRE Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as our wholly owned subsidiary (the “LRE Merger”), and, at the same time, we acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard. Under the terms of the LRE Merger Agreement, each common unit representing interests in LRE (the “LRE common units”) was converted into the right to receive 0.550 newly issued Vanguard common units.

As consideration for the LRE Merger, we issued approximately 15.4 million Vanguard common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. As consideration for our purchase of the limited liability company interests in LRE GP, we issued 12,320 Vanguard common units.

The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units.



Consideration
Market value of Vanguard’s common units issued to LRE unitholders	$	123,276
Long-term debt assumed	290,000
	413,276
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	5,606
Other current liabilities	9,018
Asset retirement obligations	39,595
Amount attributable to liabilities assumed	54,219
Less: fair value of assets acquired
Cash	11,532
Trade accounts receivable	6,822
Other current assets	4,172
Oil and natural gas properties	209,463
Derivative assets	78,725
Other assets	267
Amount attributable assets acquired	310,981
Goodwill	$	156,514

Eagle Rock Merger

On October 8, 2015, we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among us, Talon Merger Sub, LLC, our wholly owned subsidiary (“Eagle Rock Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Eagle Rock Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as our wholly owned subsidiary (the “Eagle Rock Merger”).

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Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock common unit”) was converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (without interest and rounded up to the nearest whole cent).

As consideration for the Eagle Rock Merger, Vanguard issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price per Vanguard common unit of $9.31 at October 8, 2015 and assumed $156.6 million in debt. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of Eagle Rock Merger.

The Eagle Rock Merger was completed following (i) approval by holders of a majority of the outstanding Eagle Rock common units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard common units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock common units in connection with the Eagle Rock Merger.



Consideration
Market value of Vanguard’s common units issued to Eagle Rock unitholders	$	258,282
Long-term debt assumed	156,550
Replacement share-based payment awards attributable to pre-combination services	346
	415,178
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	54,437
Other current liabilities	2,206
Derivative liabilities	2,201
Asset retirement obligations	48,633
Deferred tax liability	39,327
Other long-term liabilities	1,244
Amount attributable to liabilities assumed	148,048
Less: fair value of assets acquired
Cash	6,971
Trade accounts receivable	13,746
Other current assets	15,664
Oil and natural gas properties	462,715
Derivative assets	90,234
Other assets	9,734
Amount attributable assets acquired	599,064
Bargain Purchase Gain	$	(35,838	)

As a result of the consideration transferred being less than the fair value of net assets acquired, Vanguard reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. As part of its reassessment, Vanguard also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. Vanguard also determined that there were no non-controlling interests in the Eagle Rock Merger.

Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends between the date the parties agreed to the consideration for the Eagle Rock Merger and the date the transaction was completed, resulting in the decline of Vanguard’s unit price. Although the depressed oil and natural gas market also affected the fair value of Eagle Rock’s oil and natural gas properties, it had a more significant impact on Vanguard’s unit price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock merger, including the oil and natural gas properties, exceeded the total consideration paid. During the year ended December 31, 2016, Vanguard made adjustments to the amounts assigned to the net assets acquired based on new information obtained about facts that existed as of

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the merger date. As a result, the bargain purchase gain was reduced by $5.0 million. This adjustment is included in the net loss on acquisition of oil and natural gas properties for the year ended December 31, 2016.

6. Debt

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



			Successor			Predecessor
Description	Interest Rate	Maturity Date	December 31, 2017			December 31, 2016
Successor Credit Facility	Variable (1)	February 1, 2021	$	700,000		$	—
Successor term loan	Variable (2)	May 1, 2021	124,688			—
Senior Notes due 2024	9.0%	February 15, 2024	80,722			—
Predecessor Credit Facility	Variable (3)	April 16, 2018	—			1,269,000
Senior Notes due 2019	8.38% (4)	June 1, 2019	—			51,120
Senior Notes due 2020	7.875% (5)	April 1, 2020	—			381,830
Senior Notes due 2023	7.0%	February 15, 2023	—			75,634
Lease Financing Obligation	4.16%	August 10, 2020 (6)	15,205			20,167
Unamortized discount on Senior Notes			—			(13,167		)
Unamortized deferred financing costs			(8,639		)	(11,072		)
Total Debt			$	911,976		$	1,773,512
Less:
Long-term debt classified as current			—			(1,753,345		)
Current portion of Term Loan			(1,250		)	—
Current portion of Lease Financing Obligation			(4,750		)	(4,692		)
Total long-term debt			$	905,976		$	15,475

(1)Variable interest rate of 4.90% at December 31, 2017.

(2)Variable interest rate of 8.90% at December 31, 2017.

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

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

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

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

Successor Credit Facility

On the Effective Date, VNG, as borrower, entered into the Successor Credit Facility, by and among VNG as borrower, the Administrative Agent, also the Issuing Bank, and the Lenders. Pursuant to the Successor Credit Facility, the lenders party thereto agreed to provide VNG with the Revolving Loan. The initial borrowing base available under the Successor Credit Facility as of the Effective Date was $850.0 million and the aggregate principal amount of Revolving Loans outstanding under the Successor Credit Facility as of the Effective Date was $730.0 million. The Successor Credit Facility also includes an additional $125.0 million Term Loan. The next borrowing base redetermination is scheduled for August of 2018.

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

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

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



Year	Required Payments
2018	$	1,250
2019	1,250
2020	1,250
2021 through Maturity date	120,938

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

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

Senior Notes due 2024

On August 1, 2017, the Company issued approximately $80.7 million aggregate principal amount of Senior Notes due 2024 to certain eligible holders of the Predecessor’s second lien notes in satisfaction of their claim of approximately $80.7 million related to the Existing Notes held by such holders. The Senior Notes due 2024 were issued in accordance with the exemption from the registration requirements of the Securities Act afforded by Section 4(a)(2) of the Securities Act.

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.

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the net cash proceeds of certain equity offerings, 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.



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

Amended and Restated Intercreditor Agreement

Amended and Restated Collateral Trust Agreement

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

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

Predecessor Covenant Violations

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

Lease Financing Obligations

On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under

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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 then current fair market value. The Lease Financing Obligations also contain an early buyout option where 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%.

7. Price and Interest Rate Risk Management Activities

Commodity Derivatives

Historically, we have 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 overhedged volumes. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points.

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

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

We have also historically entered into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Successor Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The Company did not have any interest rate swaps in place at December 31, 2017.

The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at December 31, 2017.

Fixed-Price Swaps (NYMEX)



	Gas			Oil			NGLs
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average WTI Price		Gallons	Weighted Average Fixed Price
January 1, 2018 - December 31, 2018	70,242,000	$	3.00	2,712,450	$	46.59	56,721,000	$	0.61
January 1, 2019 - December 31, 2019	52,539,000	$	2.79	1,858,200	$	48.50	—	$	—
January 1, 2020 - December 31, 2020	47,227,500	$	2.75	1,393,800	$	49.53	—	$	—

Collars



	Gas					Oil
Contract Period	MMBtu	Floor Price ($/MMBtu)		Ceiling Price ($/MMBtu)		Bbls	Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
January 1, 2018 – December 31, 2018	—	$	—	$	—	—	$	—	$	—
January 1, 2019 - December 31, 2019	4,125,000	$	2.60	$	3.00	575,730	$	43.81	$	54.04
January 1, 2020 - December 31, 2020	5,490,000	$	2.60	$	3.00	659,340	$	44.17	$	55.00

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Interest Rate Swaps

We may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. These interest rate swap agreements require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. If LIBOR is lower than the fixed rate in the contract, we are required to pay the counterparty the difference, and conversely, the counterparty is required to pay us if LIBOR is higher than the fixed rate in the contract. We do not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. At December 31, 2017, the Company had no open interest rate derivative contracts.

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. The following table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):



	Successor
	December 31, 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	$	15,264		$	(13,006	)	$	2,258
Total derivative instruments	$	15,264		$	(13,006	)	$	2,258

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	$	(79,701	)	$	13,006		$	(66,695	)
Total derivative instruments	$	(79,701	)	$	13,006		$	(66,695	)



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

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our Successor Credit Facility (see Note 6 for further discussion), which is secured by our oil and natural gas properties; therefore, we are 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 $15.3 million as of December 31, 2017. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Successor Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.

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The change in fair value of our commodity and interest rate derivatives for the five months ended December 31, 2017 (Successor), the seven months ended July 31, 2017, and the years ended December 31, 2016 and 2015 (Predecessor) is as follows (in thousands):



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			December 31, 2016			December 31, 2015
Derivative asset (liability) at beginning of period, net	$	(24,894	)	$	(125	)	$	316,691		$	220,734
Purchases
Fair value of derivatives acquired	—			—			—			195,273
Net premiums and fees (received) paid for derivative contracts	—			—			(2,444		)	7,126
Net gains (losses) on commodity and interest rate derivative contracts	(55,857		)	(24,857		)	(46,939		)	169,569
Settlements
Cash settlements paid (received) on matured commodity derivative contracts	12,174			(7		)	(226,876		)	(211,723		)
Cash settlements paid on matured interest rate derivative contracts	—			95			13,398			5,227
Termination of derivative contracts	4,140			—			(53,955		)	(69,515		)
Derivative asset (liability) at end of period, net	$	(64,437	)	$	(24,894	)	$	(125	)	$	316,691

8. 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, and to long-lived assets written down to fair value when they are impaired. 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 and the initial measurement of asset retirement obligations. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as 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.

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



Level 1		Quoted prices for identical instruments in active markets.

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

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

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

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

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

Financing arrangements. The carrying amounts of our bank borrowings outstanding, including the term loans, represent their approximate fair value because our current borrowing rates are variable and do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of December 31, 2017, the carrying value of our Senior Notes due 2024 approximates its fair value. The Senior Notes due 2024 were issued at the Effective Date to holders of the predecessor Senior Notes due 2023 wherein they received full value of their claims and with terms that satisfied all counterparties. We consider the inputs to the valuation of our Senior Notes due 2024 to be Level 2.

Derivative instruments. As of December 31, 2017, our commodity derivative instruments consisted 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, ceilings and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates.

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

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

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

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	Successor
	December 31, 2017
	Fair Value Measurements Using Level 2			Assets/Liabilities at Fair Value
	(in thousands)
Assets:
Commodity price derivative contracts	$	2,258		$	2,258
Total derivative instruments	$	2,258		$	2,258

Liabilities:
Commodity price derivative contracts	$	(66,695	)	$	(66,695	)
Total derivative instruments	$	(66,695	)	$	(66,695	)



	Predecessor
	December 31, 2016
	Fair Value Measurements Using Level 2			Assets/Liabilities at Fair Value
	(in thousands)
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 in the fair value hierarchy:



	Predecessor
	2016
	(in thousands)
Unobservable inputs at January 1,	$	(5,933	)
Total gains	11,838
Settlements	(5,905		)
Unobservable inputs at December 31,	$	—

Change in fair value included in earnings related to derivatives still held as of December 31,	$	—

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

Our Predecessor applied the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represented the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill was assessed for impairment annually on October 1 or whenever indicators of impairment existed. The goodwill test was performed at the reporting unit level, which represented our oil and natural gas operations in the United States. If indicators of impairment were determined to exist, an impairment charge was recognized if the carrying value of goodwill exceeded its implied fair value. We utilized a market approach to determine the fair value of our reporting unit. The balance of goodwill was eliminated upon the application of fresh start accounting.

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At the respective measurement dates of March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test at these interim dates. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties include: (i) observable forward prices for commodities at the respective measurement date and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on the results of the second step of the interim goodwill impairment test, we recorded a non-cash goodwill impairment loss of $252.7 million during the quarter ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million. Based on our estimates, the implied fair value of our reporting unit exceeded its carrying value at the measurement dates of March 31, 2016, June 30, 2016, and December 31, 2016, therefore no additional impairment loss was recorded for the year ended December 31, 2016. Based on evaluation of qualitative factors, we determined that the goodwill impairment was primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

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 9, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” The fair value of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability are 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; and (4) the average inflation factor. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The Company periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the five months ended December 31, 2017 (Successor), we incurred impairment charges of $47.6 million as oil and natural gas properties with a net cost basis of $83.0 million were written down to their fair value of $35.4 million. In order to determine whether the carrying value of an asset is recoverable, the Company compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect the Company’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, the Company writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

9. Asset Retirement Obligations

Upon the Company's emergence from bankruptcy on August 1, 2017, as discussed in Note 3, the Company applied fresh-start accounting. This included adjusting the Asset Retirement Obligations based on the estimated fair values at the Convenience Date.

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



Asset retirement obligation at January 1, 2016	$	271,456
Liabilities added during the current period	713
Accretion expense	12,145
Change in estimate	1,267
Disposition of properties	(10,915		)
Retirements	(2,230		)
Asset retirement obligations as of December 31, 2016 (Predecessor)	272,436
Liabilities added during the current period	555
Accretion expense	6,795
Retirements	(1,161		)
Liabilities related to assets divested	(10,107		)
Change in estimate	(29		)
Asset retirement obligation at July 31, 2017 (Predecessor)	268,489
Fresh-start adjustment ⁽¹⁾	(123,320		)
Asset retirement obligation at July 31, 2017 (Successor)	145,169
Liabilities added during the current period	10,540
Accretion expense	3,975
Liabilities related to assets divested	(5,066		)
Retirements	(812		)
Change in estimate	3,618
Asset retirement obligation at December 31, 2017 (Successor)	157,424
Less: current obligations	(5,707		)
Long-term asset retirement obligation at December 31, 2017 (Successor)	$	151,717

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

Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2016, we reviewed the actual abandonment costs with previous estimates and, as a result, increased our estimates of future asset retirement obligations by a net $1.3 million, to reflect increased costs incurred for plugging and abandonment on certain wells. In addition, the Company further reviewed its abandonment liabilities and determined the need to record additional asset retirement obligation of approximately $3.6 million in 2017.

During the five month period ended December 31, 2017 (Successor), inputs to the valuation of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability 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 6.2% and 6.4%; and (4) the average inflation factor of 1.8%. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are sensitive and subject to change.

10. Commitments and Contingencies

Transportation Demand Charges

As of December 31, 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 December 31, 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.

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	Demand Charges
	(in thousands)
2018	$	1,009
2019	820
2020	410
Total	$	2,239

Lease Commitments

Rent expense for our office leases was $0.7 million, $1.1 million, $3.4 million and $2.3 million for the five months ended December 31, 2017 (Successor), seven months ended July 31, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), respectively. The rent expense relate to the lease of our office space in Houston, Texas as well as office leases in our other operating areas. As of December 31, 2017, the minimum contractual obligations were approximately $10.4 million in the aggregate. Our policy is to amortize the total payments under the lease agreement on a straight-line basis over the term of the lease.



	Lease Payments
	(in thousands)
2018	$	1,202
2019	1,149
2020	1,135
2021	1,169
2022	1,204
Thereafter	4,504
Total	$	10,363

Development Commitments

We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. As of December 31, 2017, total estimated costs to be spent in 2018 is approximately $25.3 million of which $20.6 million relates primarily to our Pinedale field drilling and completion commitments in the Green River Basin.

Legal Proceedings

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

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

We are also a party to separate legal proceedings as further discussed below.

Litigation Relating to Vanguard’s 2015 merger with LRR Energy, L.P.

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al., Civil Action No. 4:15-cv-2017, in the United States District Court for the Southern District of Texas, Houston Division. These lawsuits have been voluntarily dismissed or nonsuited.

On August 22, 2016, the LRE Lawsuit Defendants filed a motion to dismiss the LRE Lawsuit in its entirety under Federal Rule of Civil Procedure 12(b)(6). This motion was denied on March 13, 2017. On November 3, 2017, the LRE Plaintiff filed a motion for an order certifying the action as a class action and Defendants filed motions for summary judgment under Federal Rule of Civil Procedure 56. On December 29, 2017, the Court denied the LRE Lawsuit Defendants’ motions for summary judgment, holding that the LRE Plaintiff was entitled to complete discovery on his claims, but that the LRE Lawsuit Defendants could renew their motions for summary judgment if discovery shows there are no genuine issue of material fact precluding judgment as a matter of law in the LRE Lawsuit Defendants’ favor. On January 2, 2018, the Court granted the LRE Plaintiff’s motion for class certification, and preliminarily certified the LRE Plaintiff’s claims as a class action on behalf of certain former LRE unitholders.

Litigation Relating to the Debt Exchange

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LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC in the Southern District of New York. The lawsuit was styled Kaufmann et al v. Vanguard Natural Resources, LLC et al, Case No. 1:16-cv-02743.

Litigation Relating to Alleged Royalty Underpayment

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We are also defendants in certain legal proceedings arising in the normal course of our business. Management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow, although the ultimate outcome and impact of such legal proceedings on the Company cannot be predicted with certainty. Furthermore, our insurance may not be adequate to cover all liabilities that may arise out of claims brought against us. If one or more negative outcomes were to occur relative to these matters, the aggregate impact to our financial position, results of operations or cash flow could be material. As of December 31, 2017, we have not reserved any loss contingencies related to our legal proceedings in our financial statements because our management believes a loss arising from these proceedings is not probable and reasonably estimable.

11. Stockholders’ Equity (Members’ Deficit)

Cancellation of Units and Issuance of Common Stock

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

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


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


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


•	678,405 shares of Common Stock were issued to participants in the 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 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);

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•	1,023,000 shares of 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 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 Common Stock were issued to holders of the Predecessor’s Preferred Units; and


•	44,220 shares of Common Stock were reserved for general unsecured claimholders. These shares were ultimately issued on December 21, 2017.

Warrant Agreement

On the Effective Date, the Company entered into the Warrant Agreement with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued (i) to electing holders of the Predecessor’s (A) Series A Preferred Units, (B) Series B Preferred Units, and (C) Series C Preferred Units, the Preferred Unit New Warrants, which are exercisable to purchase up to 621,649 shares of the New Common Stock as of the Effective Date, subject to dilution; and (ii) to electing holders of Predecessor’s Common Units, the Common Unit New Warrants, which are 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 is February 1, 2021. The strike price for the Preferred Unit New Warrants is $44.25, and the strike price for the Common Unit New Warrants is $61.45.

The Company allocated approximately $11.7 million of the Enterprise Value to the warrants which is reflected in “Successor Additional paid-in capital” on the consolidated balance sheet at December 31, 2017.

Management Incentive Plan

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

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

The MIP is administered by the Committee or, in certain instances, its designee. Employees, directors, and consultants of the Company and its subsidiaries are eligible to receive awards of stock options, restricted stock, restricted stock units (“RSUs”) or other stock-based awards at the Committee or its designee's discretion.

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

Dividends/Distributions

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

Earnings per Share/Unit

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

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The diluted earnings per share calculation excludes approximately 1.3 million warrants that were antidilutive for the five months ended December 31, 2017. In addition, diluted earnings per share calculation also excludes 11,250 restricted stock units that were antidilutive for the five months ended December 31, 2017. For the seven months ended July 31, 2017, 13.5 million phantom units were excluded from the calculation of diluted earnings per unit as they were antidilutive. For the year ended December 31, 2016, 3.8 million phantom units were excluded from the calculation of diluted earnings per unit for each period, due to their antidilutive effect as we were in a loss position.

12. Share-Based Compensation

Effect of Emergence from Bankruptcy on Unit-Based Compensation

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

Predecessor Employment Agreements

On March 18, 2016, our Predecessor and VNR Holdings, LLC, the Predecessor’s wholly owned subsidiary (“VNR Holdings”), entered into amended and restated employment agreements (the “Predecessor Employment Agreements”) with each of Messrs. Smith, Robert and Pence (each, a “Predecessor Executive” and collectively, the “Predecessor Executives”). The Predecessor Employment Agreements were effective January 1, 2016, and the initial term was set to end on January 1, 2019.

On the Effective Date, in connection with the Company’s emergence from the Chapter 11 Filings, the Predecessor Employment Agreements were amended and restated as set forth below in “Post-Emergence Employment Agreements.”

In connection with the entry into the Predecessor Employment Agreements, the Predecessor also entered into restricted unit agreements and phantom unit agreements with the Predecessor Executives, subject to the terms of the Predecessor LTIP.

On the Effective Date, in connection with the Company’s emergence from the Chapter 11 Filings, all of the Predecessor’s equity was canceled.

Post-Emergence Employment Agreements

Sloan Employment Agreement

On September 26, 2017, the Company and Richard Scott Sloan entered into an offer letter of employment, which established general terms of his employment. Effective as of October 31, 2017, the Company entered into an employment agreement (“Sloan Employment Agreement”) with Mr. Sloan. The initial term of the Sloan Employment Agreement ends on December 31, 2020, with a subsequent 12-month term extension automatically commencing on January 1, 2021 and expiring on January 1, 2022, provided that neither the Company nor Mr. Sloan delivers a timely non‑renewal notice prior to the expiration date.

The Sloan Employment Agreement provides that Mr. Sloan is entitled to an annual base salary of $510,000. In addition, the Board has the discretion to increase the base salary of Mr. Sloan, at any time if it deems an increase is warranted. Subject to certain terms and conditions, the Board may not reduce Mr. Sloan’s base salary without his prior written approval.

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except that the Amended and Restated Sloan Agreement is updated to reflect Mr. Sloan’s position of President and Chief Executive Officer, as well as (i) his annual base salary of $700,000, (ii) his target annual performance-based bonus award equal to 100% of his annual base salary, and (iii) the amount of his initial equity grant.

Management Incentive Plan

As discussed in Note 11, “Stockholders’ Equity (Members’ Deficit),” on August 22, 2017, the Company’s board of directors approved the MIP, which will assist the Company in attracting, motivating and retaining key personnel and will align the interests of participants with those of stockholders.

MIP Restricted Stock Units

The MIP allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is expensed over the requisite service period.

On October 31, 2017, 11,250 restricted stock unit awards were granted to various directors with a grant-date fair value of $19.50 per unit of which 3,750 restricted stock units vested immediately while the remaining 7,500 restricted stock units will vest over a period of three years.

As of December 31, 2017, we had unrecognized compensation expense of $0.1 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.8 years.

Share-based compensation for the predecessor and successor periods are not comparable. Our Consolidated Statements of Operations reflect non-cash compensation related to our MIP and the Predecessor Incentive Plan of $0.1 million for the period of August 1, 2017 through December 31, 2017 (Successor), while for the period of January 1, 2017 through July 31, 2017 (predecessor) and the years ended December 31, 2016 and 2015 (Predecessor) the expense was $5.8 million, $10.2 million and $18.6 million, respectively.

Predecessor Unit-Based Compensation Awards

Restricted Units

The following table represents the restricted unit award activity for the seven months ended July 31, 2017 (Predecessor):



	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	(14,637	)	$	16.93
Vested	(257,497	)	$	20.80
Non-vested restricted units at July 31, 2017	375,650		$	18.11
Restricted units canceled upon emergence from bankruptcy	(375,650	)	$	18.11
Restricted units upon emergence	—		$	—

During the seven months ended July 31, 2017 (Predecessor), the Company did not issue any restricted units to employees and directors. For the years ended December 31, 2016 and 2015, the Company issued 7,500 units and 562,393 units, respectively, of restricted units to employees and directors. The weighted average grant-date fair value of restricted units granted was $3.11 and $15.17 during the years ended December 31, 2016 and 2015, respectively. All restricted units were cancelled upon emergence from bankruptcy.

Phantom Units

The following table represents the phantom unit award activity for the seven months ended July 31, 2017 (Predecessor):

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	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	(73,257	)	$	2.04
Vested	(956,830	)	$	4.31
Non-vested phantom units at July 31, 2017	13,691,150		$	1.02
Phantom units canceled upon emergence from bankruptcy	(13,691,150	)	$	1.02
Phantom units upon emergence	—		$	—

In January 2017, the executives were granted a total of 10,611,940 phantom units in accordance with their respective employment agreements. Also, during the seven months ended July 31, 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. For the year ended December 31, 2016, the Company granted 3,712,450 phantom unit awards to employees and directors with a weighted average grant-date fair value of $2.56. The Company did not grant any phantom units during the year ended December 31, 2015. All phantom units were cancelled upon emergence from bankruptcy.

13. Income Taxes

On December 22, President Trump signed into law the Tax Act that significantly reforms the U.S. tax code. The provisions of the Tax Act that impact us include, but are not limited to: (i) a permanent reduction of the corporate income tax rate from 35% to 21%, (ii) a limitation of the deduction for certain net operating losses to 80% of the current year taxable income, (iii) an elimination of net operating loss carryback coupled with an indefinite net operating loss carryforward, (iv) a partial limitation on the deductibility of business interest expense, and (v) immediate deductions for certain new investments.

In response to the Tax Act, the SEC staff issued SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC Topic 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC Topic 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC Topic 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.

Our accounting for the following elements of the Tax Act is incomplete. However, we were able to make reasonable estimates of certain effects and, therefore, recorded provisional adjustments as follows:

Reduction of US Federal Corporate Tax Rate: The Tax Act reduces the corporate tax rate to 21%, effective January 1, 2018. In connection with the re-measurement of deferred taxes to the 21% tax rate, we have recorded a provisional increase of $19.8 million to deferred tax expense for the year ended December 31, 2017. There was no earnings impact for the revaluation of our domestic deferred tax assets, which include our net operating losses, as they continue to be fully reserved. While we are able to make a reasonable estimate of the impact of the reduction in corporate rate, it may be affected by other analyses related to the Tax Act, including, but not limited to, changes to our cost recovery assumptions and the state tax effect of adjustments to federal temporary differences.

Net Operating Loss Utilization: With respect to net operating losses generated after 2017, the Tax Act eliminated carrybacks, provided an indefinite carryforward period, and lowered the maximum deduction to 80% of corporate taxable income. On a provisional basis we have determined that there is no impact to the valuation allowance for changes to the net operating loss standards under the Tax Act

Immediate Expensing of Certain Investments: The Tax Act provides accelerated expensing of certain assets placed in service after September 27, 2017. For the first five years (through 2022), the provision allows for 100% immediate expensing of qualified property. Thereafter, accelerated depreciation will be reduced over each of the next four years (through 2026). We have not yet completely inventoried and analyzed our 2017 capital expenditures that qualify for bonus expensing. We have recorded a provisional tax depreciation expense of $14.0 million which does not include full expensing of all qualifying capital expenditures.

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Prior to July 31, 2017, the Predecessor was a limited liability corporation treated as a partnership for federal and state income tax purposes, in which the taxable income tax or loss of the Predecessor were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. Therefore, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. Tax benefits of $0.5 million, $1.3 million, and $0.3 million are included in our Consolidated Statements of Operations for the seven months ended July 31, 2017 (Predecessor) and the years ended December 31, 2016, and 2015 (Predecessor), respectively, as a component of Selling, general and administrative expenses.

The deferred tax effects of the Company’s transition to a C corporation are included in the period ended July 31, 2017. Since the Company’s net deferred tax asset as of July 31, 2017 was fully reserved, there was no impact to the consolidated financial statements.

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:



	Successor
	Five Months Ended December 31, 2017
Federal statutory rate	35.0	%
Permanent items	(2.0	)%
Federal statutory rate change	(17.8	)%
State, net of federal tax benefit	3.0	%
Valuation allowance adjustments	(18.2	)%
Effective rate	—	%

Deferred income tax balances representing the tax effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities are as follows:



	Successor
	December 31, 2017
Deferred tax assets:
Net operating loss carryforwards	$	2,957
Asset retirement obligation	39,084
Derivative instruments	7,655
Accrued Liabilities	6,681
Bad debts	1,489
Investment in subsidiaries	4,827
Other	31
Valuation allowance	(35,447		)
Total deferred tax assets	27,277
Deferred tax liabilities:
Oil & natural gas property	(27,277		)
Total deferred tax liabilities	(27,277		)
Net deferred tax assets (liabilities)	$	—

At December 31, 2017, the Company has U.S. domestic net operating loss carry forwards of approximately $6.6 million which will begin to expire in varying amounts beginning in 2035 and state net operating loss carry forwards of approximately $6.6 million which will expire in varying amounts beginning in 2023.

In assessing the realizability of net deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management

136

considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2017, based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is not more likely than not that the Company will realize the benefits of these deductible differences.

In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2017. The tax year 2017 remains open to examination for federal and state income tax purposes.

Supplemental Selected Quarterly Financial Information

Financial information by quarter (unaudited) is summarized below.



	Predecessor												Successor
(in thousands except per share/unit amounts)	Quarter Ended			Quarter Ended			One Month Ended						Two Months Ended			Quarter Ended
	March 31			June 30			July 31			Total			September 30			December 31			Total
2017
Oil, natural gas and NGLs sales	$	118,756		$	106,868		$	21,024		$	246,648		$	79,800		$	125,818		$	205,618
Net gains (losses) on commodity derivative contracts	7			(12,875		)	(12,019		)	(24,887		)	(32,352		)	(23,505		)	(55,857		)
Total revenues	$	118,763		$	93,993		$	9,005		$	221,761		$	47,448		$	102,313		$	149,761
Total costs and expenses⁽¹⁾	$	84,570		$	81,066		$	29,836		$	195,472		$	75,105		$	112,562		$	187,667
Impairment of oil and natural gas properties	$	—		$	—		$	—		$	—		$	—		$	47,640		$	47,640
Interest expense	$	16,440		$	13,832		$	5,004		$	35,276		$	9,615		$	14,589		$	24,204
Net gain on divestiture of oil and natural gas properties	$	—		$	—		$	—		$	—		$	—		$	4,450		$	4,450
Reorganization items	$	(26,746	)	$	(53,221	)	$	988,452		$	908,485		$	—		$	(6,488	)	$	(6,488	)
Net income (loss)	$	(8,908	)	$	(53,871	)	$	963,090		$	900,311		$	(37,236	)	$	(74,042	)	$	(111,278	)
Net (income) loss attributable to non-controlling interest	$	(17	)	$	5		$	(1	)	$	(13	)	$	(61	)	$	(71	)	$	(132	)
Net income (loss) attributable to Vanguard shareholders/unitholders	$	(8,925	)	$	(53,866	)	$	963,089		$	900,298		$	(37,297	)	$	(74,113	)	$	(111,410	)
Distributions to Preferred unitholders	$	(2,230	)	$	—		$	—		$	(2,230	)	$	—		$	—		$	—
Net income (loss) attributable to Common shareholders/Common and Class B unitholders	$	(11,155	)	$	(53,866	)	$	963,089		$	898,068		$	(37,297	)	$	(74,113	)	$	(111,410	)

Net income (loss) per share/unit:
Basic and diluted	$	(0.08	)	$	(0.41	)	$	7.33		$	6.84		$	(1.86	)	$	(3.69	)	$	(5.55	)

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	Quarters Ended
	March 31			June 30			September 30			December 31			Total
	(in thousands, except per unit amounts)
2016
Oil, natural gas and NGLs sales	$	81,440		$	93,476		$	105,186		$	108,578		$	388,680
Net gains (losses) on commodity derivative contracts	31,759			(68,610		)	21,099			(28,320		)	(44,072		)
Total revenues	$	113,199		$	24,866		$	126,285		$	80,258		$	344,608
Total costs and expenses ⁽¹⁾	$	110,070		$	100,185		$	94,759		$	94,603		$	399,617
Impairment of oil and natural gas properties	$	207,764		$	157,894		$	—		$	128,612		$	494,270
Impairment of goodwill	$	—		$	—		$	252,676		$	—		$	252,676
Interest expense	$	25,704		$	23,932		$	22,976		$	22,755		$	95,367
Net losses on acquisitions of oil and natural gas properties	$	—		$	(1,665	)	$	(2,117	)	$	(1,197	)	$	(4,979	)
Gain on extinguishment of debt	$	89,714		$	—		$	—		$	—		$	89,714
Net loss	$	(145,260	)	$	(260,749	)	$	(245,368	)	$	(163,630	)	$	(815,007	)
Net (income) loss attributable to non-controlling interest	$	(24	)	$	(40	)	$	(27	)	$	9		$	(82	)
Net loss attributable to Vanguard unitholders	$	(145,284	)	$	(260,789	)	$	(245,395	)	$	(163,621	)	$	(815,089	)
Distributions to Preferred unitholders	$	(6,690	)	$	(6,689	)	$	(6,690	)	$	(6,689	)	$	(26,758	)
Net loss attributable to Common and Class B unitholders	$	(151,974	)	$	(267,478	)	$	(252,085	)	$	(170,310	)	$	(841,847	)

Net loss per Common and Class B unit:
Basic and diluted	$	(1.16	)	$	(2.04	)	$	(1.92	)	$	(1.30	)	$	(6.41	)


(1)	Includes lease operating expenses, production and other taxes, depreciation, depletion, amortization and accretion, and selling, general and administration expenses.

138

Supplemental Oil and Natural Gas Information

We are an independent exploration and production company focused on the production and development of oil and natural gas properties in the United States.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

Capitalized costs related to oil, natural gas and NGLs producing activities and related accumulated depletion, amortization and accretion were as follows at December 31:



	Successful Efforts Method			Full Cost Method
	Successor			Predecessor
	2017			2016
	(in thousands)
Proved properties	$	1,560,552		$	4,725,692
Unproved properties	85,393			—
	1,645,945			4,725,692
Aggregate accumulated depletion, amortization and impairment	(112,553		)	(3,867,439		)
Net capitalized costs	$	1,533,392		$	858,253

Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

Costs incurred in oil, natural gas and NGLs producing activities, whether capitalized or expensed, were as follows for the years ended December 31:



	Successful Efforts Method		Full Cost Method
	Successor		Predecessor
	Five Months Ended December 31, 2017		Seven Months Ended July 31, 2017		Years Ended December 31,
	Five Months Ended December 31, 2017		Seven Months Ended July 31, 2017		2016		2015
	(in thousands)
Property acquisition costs	$	—	$	—	$	—	$	707,853
Development costs	79,246		46,315		64,537		112,639
Total cost incurred	$	79,246	$	46,315	$	64,537	$	820,492

No internal costs or interest expense were capitalized in 2017, 2016 or 2015.

139

Oil and Natural Gas Reserves (Unaudited)

Net quantities of proved developed and undeveloped reserves of oil, natural gas and NGLs and changes in these reserves during the years ended December 31, 2017, 2016 and 2015 are presented below. Estimates of proved reserves included in this Annual Report at December 31, 2017 were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. In accordance with our internal policies and procedures related to reserve estimates, annually we engage an independent petroleum engineering firm to audit properties comprising at least 80% of our reserves. For the year ended December 31, 2017, we engaged Miller and Lents, and for the years ended December 31, 2016 and 2015, we engaged DeGolyer and MacNaugton.



	Gas (in MMcf)		Oil (in MBbls)	NGL (in MBbls)
Net proved reserves
January 1, 2015	1,475,867		50,049	42,529
Revisions of previous estimates	(133,234)		(4,208)	(2,151)
Extensions, discoveries and other	46,664		640	659
Purchases of reserves in place	271,504		21,826	20,836
Sales of reserves in place	—		(225)	—
Production	(106,615)		(4,008)	(3,489)
December 31, 2015	1,554,186		64,074	58,384
Revisions of previous estimates	(438,527)		(11,052)	(5,823)
Extensions, discoveries and other	14,617		722	126
Purchases of reserves in place	—		—	—
Sales of reserves in place	(133,253	)	(6,792)	(12,217	)
Production	(108,107)		(4,660)	(3,716)
December 31, 2016	888,916		42,292	36,754
Revisions of previous estimates	(35,865)		(1,716)	(2,782)
Extensions, discoveries and other	604,009		6,391	8,126
Purchases of reserves in place	—		—	—
Sales of reserves in place	(5,462)		(4,229)	(424	)
Production	(94,009)		(3,768)	(3,319)
December 31, 2017	1,357,589		38,970	38,355

Proved developed reserves
December 31, 2015	1,069,942		54,945	42,140
December 31, 2016	888,916		42,292	36,754
December 31, 2017	831,479		34,257	31,381

Proved undeveloped reserves
December 31, 2015	484,244		9,129	16,244
December 31, 2016	—		—	—
December 31, 2017	526,110		4,713	6,974

Revisions of previous estimates of reserves are a result of changes in oil and natural gas prices, production costs, well performance and the reservoir engineer’s methodology. Our reserves increased by 257.6 Bcfe during the year ended December 31, 2015 due to properties acquired in the LRE and Eagle Rock Mergers completed during 2015. Our reserves decreased by 925.7 Bcfe during the year ended December 31, 2016 due primarily to the reclassification of proved undeveloped reserves to contingent resources due to uncertainties discussed below and the related reduction in proved developed reserves value resulting from shorter economic field life, which caused both a reduction in proved developed reserves volumes and significant acceleration of abandonment costs for all fields. Our reserves increased by 458.3 Bcfe during the year ended

140

December 31, 2017, primarily due to additions of undeveloped reserves which were classified as contingent resources as of December 31, 2016, offset by properties divested in the Permian and Williston Basins during 2017.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2017.

Our proved undeveloped reserves at December 31, 2017, as estimated by our internal reservoir engineers, were 596.2 Bcfe, consisting of 4.7 MMBbls of oil, 526.1 Bcf of natural gas and 7.0 MMBbls of NGLs. During 2017, our proved undeveloped reserves increased by approximately 596.2 Bcfe primarily due to additions of undeveloped reserves which were classified as contingent resources as of December 31, 2016, due to uncertainty regarding the availability of capital that would be required to develop the PUD reserves.

We did not report any proved undeveloped reserves at December 31, 2016, consequently, we did not have any proved undeveloped reserves to convert to proved developed reserves during 2017.

Development Plans.

We expect to spend approximately 68% of our planned five year future development costs within the next three years as reflected in our reserve report.

Our development plan for drilling proved undeveloped wells includes the drilling of 197 net wells before the end of 2022 at an estimated cost of $524.8 million. This development plan calls for the drilling and completion of 59 net wells during 2018, 41 net wells during 2019, 43 net wells during 2020, 34 net wells during 2021 and 20 net wells during 2022. Additionally, the expected plan of development of our proved undeveloped reserves over the next five years is as follows:



	Percent of Proved Undeveloped Reserves Expected to be Converted
2018	25%
2019	22%
2020	21%
2021	19%
2022	13%
Total	100%

Results of operations from producing activities were as follows for the years ended December 31:

141



	Successor			Predecessor
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			Years Ended December 31,
	Five Months Ended December 31, 2017			Seven Months Ended July 31, 2017			2016			2015
	(in thousands)			(in thousands)
Production revenues	$	205,618		$	246,648		$	388,680		$	397,227
Production costs ⁽¹⁾	(93,323		)	(108,278		)	(198,309		)	(187,230		)
Depreciation, depletion and amortization	(70,826		)	(56,919		)	(134,338		)	(234,944		)
Impairment of oil and natural gas properties	(47,640		)	—			(494,270		)	(1,842,317		)
Results of operations from producing activities	$	(6,171	)	$	81,451		$	(438,237	)	$	(1,867,264	)


(1)	Production cost includes lease operating expenses, transportation, gathering, processing and compression

fees, and production related taxes, including ad valorem and severance taxes.

The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at December 31 is as follows:



	2017			2016			2015
	(in thousands)
Future cash inflows	$	5,514,270		$	3,661,078		$	7,500,445
Future production costs	(2,634,887		)	(2,244,373		)	(3,411,879		)
Future development costs	(554,807		)	(55,298		)	(664,254		)
Future net cash flows before income taxes	2,324,576			1,361,407			3,424,312
Future income taxes ⁽¹⁾	(232,912		)	—			—
Future net cash flows	2,091,664			1,361,407			3,424,312
10% annual discount for estimated timing of cash flows	(1,018,036		)	(507,638		)	(1,716,133		)
Standardized measure of discounted future net cash flows ⁽²⁾	$	1,073,628		$	853,769		$	1,708,179

(1)

Future income taxes are calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and natural gas operations.There are no future income tax expenses at December 31, 2016, or December 31, 2015, because the Predecessor was not subject to federal income taxes. See Note 13 of the Notes to the Consolidated Financial Statements for additional information about income taxes.

(2)

For the December 31, 2017, 2016, and 2015 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using the average oil and natural gas price based upon the 12-month average price of $51.22, $42.60 and $50.20 per barrel of crude oil, respectively, $2.99, $2.47 and $2.62 per MMBtu for natural gas, respectively, adjusted for quality, transportation fees and a regional price differential, and the volume-weighted average price of $19.24, $13.43 and $16.14 per barrel of NGLs. The NGLs prices were calculated using the differentials for each property to a West Texas Intermediate reference price of $51.22, $42.60 and $50.20 for the years ended December 31, 2017, 2016, and 2015, respectively. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price changes and the effects of our hedging activities.

The following are the principal sources of change in our standardized measure of discounted future net cash flows:

142



	Year Ended December 31, ⁽¹⁾
	2017			2016			2015
	(in thousands)
Sales and transfers, net of production costs	$	(250,667	)	$	(189,111	)	$	(209,997	)
Net changes in prices and production costs	360,867			(681,575		)	(1,790,820		)
Extensions discoveries and improved recovery, less related costs	235,949			16,960			17,031
Changes in estimated future development costs	30,584			312,032			278,884
Previously estimated development costs incurred during the period	—			20,115			63,624
Revision of previous quantity estimates	(55,606		)	(276,257		)	(134,818		)
Accretion of discount	85,377			170,818			296,342
Net change in income taxes	(121,155		)	—			—
Purchases of reserves in place	—			—			520,367
Sales of reserves in place	(32,989		)	(214,419		)	(4,468		)
Change in production rates, timing and other	(32,501		)	(12,973		)	(291,389		)
Net change	$	219,859		$	(854,410	)	$	(1,255,244	)


(1)	This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

143

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES


(a)	Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of 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) under the Exchange Act) as of the end of the period covered by this Annual 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 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 Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2017.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2017, is set forth in Item 9A(b) below.


(b)	Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting, as defined by SEC rules adopted under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. It consists of policies and procedures that:


•	Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;


•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and


•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this assessment, we used the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2017.


(c)	Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

144

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

The Board of Directors of the Company (the “Board”) consists of seven members. In connection with the Chapter 11 proceedings, the Predecessor entered into a Restructuring Support Agreement, as further amended (the “RSA”) with certain significant equity holders set forth therein, including, among others, Monarch Alternative Capital LP (“Monarch”), Marathon Asset Management (“Marathon”) and Contrarian Capital Management (“Contrarian”) (collectively, the “Senior Commitment Parties”). Pursuant to the RSA, the Senior Commitment Parties were granted the right to select up to five individuals to serve as directors on the new Board to be appointed as of the Effective Date. As of the Effective Date, the Senior Commitment Parties appointed four directors. Monarch, Marathon and Contrarian selected Messrs. Citarrella, Alexander and Morris, their respective employees, to serve as directors of the Board. The Senior Commitment Parties also appointed R. Scott Sloan, who is not employed by any of the Senior Commitment Parties, to serve on the Board as of the Effective Date.

The following sets forth information concerning each member of our Board as of March 21, 2018, including each director’s name, age, principal occupation or employment for at least the past five years and the period for which he has served as a director of the Company. Each director’s initial term will expire at the annual meeting of stockholders. There are no family relationships among any of our directors or executive officers or arrangements.



Name	Age	Position with Vanguard	Director Since
R. Scott Sloan	53	President, Chief Executive Officer and Director	August 1, 2017
Joseph Citarrella	31	Independent Director and Chairman	August 1, 2017
Randall M. Albert	60	Independent Director	September 26, 2017
Michael Alexander	40	Independent Director	August 1, 2017
W. Greg Dunlevy	62	Independent Director	October 17, 2017
Joseph Hurliman Jr.	60	Independent Director	February 21, 2018
Graham Morris	45	Independent Director	August 1, 2017

R. Scott Sloan has served as our President and Chief Executive Officer since January 2018 and as a director since August 2017. Prior to his appointment as President and Chief Executive Officer, Mr. Sloan had served as our Executive Vice President and Chief Financial Officer since September 26, 2017 and was a member of the Compensation Committee of the Board and the Chairman of the Audit Committee of the Board from the Effective Date until September 26, 2017. From 2015 to 2016, Mr. Sloan served as Senior Vice President, Strategy, Commercial and Global New Business Development at Hess Corporation, where he oversaw strategic planning, new business development, and oil and gas marketing. Prior to 2015, Mr. Sloan served in various senior leadership positions throughout a 25 year career at BP, including as President of BP Russia from 2012 through 2014 and as Chief Financial Officer of BP Russia from 2009 through 2012. While at BP, Mr. Sloan also served as Director of Mergers and Acquisitions and in several regional Chief Financial Officer roles. Mr. Sloan has also held board positions with TNK Holdings, Slavneft, Rusia Petroleum, In Salah Sales, and Medgaz. He holds a B.A. in Economics from Colgate University and M.B.A. in Corporate Finance from the University of Chicago. Mr. Sloan’s extensive background in the energy industry and his financial background will provide him with valuable experience on which he can draw while serving as a member of the Board.

Joseph Citarrella has served as the Chairman of the Board since August 2017. In May 2012, Mr. Citarrella joined Monarch, a New York-based private investment firm, and currently serves as a Managing Principal. From July 2011 through May 2012, Mr. Citarrella was an Associate at Goldman Sachs in the Global Investment Research group, covering the integrated oil, exploration and production, and refining sectors, where he also previously served as a Financial Analyst. Mr. Citarrella

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holds a B.A. in Economics from Yale University. Mr. Citarrella’s extensive financial background and his experience researching the energy sector bring important experience and skill to the Board.

Randall Albert has served as a director since September 2017. Mr. Albert is the President and Chief Executive Officer of Shale Advisory Group, LLC. Mr. Albert founded Shale Advisory Group, LLC in 2013, after retiring from CONSOL Energy Inc. (“CONSOL”) in November 2013, where he had served as Chief Operating Officer - Gas since 2010. During his time at CONSOL, Mr. Albert led the rapid development of CONSOL’s Marcellus Shale and emerging Utica Shale programs. Mr. Albert has served in various senior leadership positions in the energy sector throughout his 34 year career. Mr. Albert also currently serves as the lead independent director of Eclipse Resources Corporation, a non-executive board member at Wellsite Fishing & Rental Services, LLC, and as a member of the advisory board of Black Bay Energy Capital. Mr. Albert previously served as the chairman of the Marcellus Shale Coalition and was a member of the Virginia Tech Mining and Minerals Engineering Advisory Board. Mr. Albert holds a B.S. in Mining Engineering from Virginia Tech, where in 2016 he was inducted into the Virginia Tech Academy of Engineering Excellence, the highest honor bestowed on College of Engineering graduates. Mr. Albert’s decades long experience in the energy industry makes him well qualified to serve on the Board.

Michael Alexander has served as a director since August 2017. Mr. Alexander is a Managing Director at Marathon, a New York based investment manager, which he joined in March 2005. Mr. Alexander focuses on corporate credit and restructuring transactions and covers multiple sectors including energy. Mr. Alexander spent three years in Marathon’s London office from 2006 to 2009 helping build Marathon’s European credit business, before returning to New York. Prior to joining Marathon, he worked at The Blackstone Group in its restructuring advisory business (now PJT Partners). Mr. Alexander holds a B.S. in Commerce from the University of Virginia with a concentration in finance. Mr. Alexander’s extensive financial background and his experience covering the energy industry bring important experience and skill to the Board.

W. Greg Dunlevy has served as a director since October 2017. In 2015, Mr. Dunlevy retired from Kosmos Energy Ltd. (“Kosmos”), where he was one of the Founding Partners. Mr. Dunlevy joined Kosmos in 2003 and served in a variety of senior leadership roles, including Executive Vice President and Chief Financial Officer. Prior to Kosmos, Mr. Dunlevy served as Vice President of Finance and Administration for the Triton Energy Ltd. business unit of Amerada Hess Corporation (now Hess Corporation) following its acquisition of Triton, where he was Senior Vice President and Chief Financial Officer. Mr. Dunlevy began his career with ARCO, where he served in a variety of positions including for ARCO Petroleum Products Company, the ARCO Oil and Gas Company, and Lyondell Petrochemical Company subsidiaries. Mr. Dunlevy holds a B.S. in Chemistry from the College of William & Mary and an M.B.A. from Harvard Business School. Mr. Dunlevy’s extensive energy industry and financial background bring important experience and skill to the Board.

Joseph Hurliman Jr. has served as a director since February 2018. Mr. Hurliman served as the President and Chief Executive Officer of Discovery Natural Resources LLC, a private upstream oil and gas company (“Discovery”). Mr. Hurliman also served as a board advisor to FIML Natural Resources, LLC, the predecessor company of Discovery. In 2012, Mr. Hurliman founded Hurliman Enterprises LLC, an oil and gas consultancy firm. Mr. Hurliman brings over 35 years of exploration & development experience to the Board. Prior to Discovery, Mr. Hurliman held a variety of roles in BP and its JV partnerships, with over 30 years in North and South America, the UK and Russia. He held a number of senior positions in reservoir and asset management on some of BP’s largest projects. Mr. Hurliman holds a B.A. in Chemistry from Whitman College and B.S. in Chemical Engineering from The California Institute of Technology. Mr. Hurliman brings to the Board his expertise in exploration appraisal and field development, production operations and oil and gas reserves management.

Graham Morris has served as a director since August 2017. Since March 2011 Mr. Morris has served as the Distressed Equity Strategy Head for Contrarian and is responsible for managing the firm’s Distressed Equity Strategy. From January 2006 through March 2011, Mr. Morris was the Assistant Portfolio Manager of Contrarian Long Short and Contrarian Distressed Equity. Before joining Contrarian, Mr. Morris was an Analyst at Advent Capital Management L.L.C. from 2003 to 2005. At Advent Capital, Mr. Morris covered event driven and deep value equities as well as high yield and convertible bond investments. From 2000 to 2002, he was an Associate in the Telecom & Media Investment Banking group at UBS where he advised corporate clients on restructuring activities, high yield offerings, initial public offerings and mergers and acquisitions.

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Mr. Morris graduated Phi Beta Kappa with a B.A. in Economics from the University of Texas at Austin and holds a M.B.A. from Columbia Business School. Mr. Morris’ extensive financial background brings important experience and skill to the Board.

Board Structure and Procedures for Security Holders to Nominate Directors

Upon our emergence from Chapter 11, our Certificate of Incorporation and our Bylaws reflected changes to the structure of the Board and to procedures by which holders of our securities may recommend nominees to our Board.

Our Certificate of Incorporation provides that the total number of directors constituting the entire Board shall not be less than one (1) nor more than fifteen (15), which number may be changed from time to time by resolution of a majority of the Board. Our Bylaws provide that no director may be removed, with or without cause, without the affirmative vote or written consent of the holders of at least a majority of the voting power of the shares entitled to vote generally in the election of directors of the Company. The number of directors that comprise the Board will be fixed from time to time exclusively by the Board as provided in our Bylaws.

Our Bylaws establish the procedures by which our stockholders may nominate directors to the Board in certain circumstances. Prior to the date on which our Common Stock is listed on a national securities exchange, or the date on which we consummate an initial public offering, any vacancy on the Board shall be filled only by the affirmative vote of the holders of a majority in voting power of our stock (including any series of preferred stock then outstanding, if any). On or after the date on which our Common Stock is listed on a national securities exchange, or we consummate an initial public offering, subject to the rights, if any, of the holders of shares of any class or series of preferred stock of the Company then outstanding to designate a director to fill a vacancy as set forth in the instrument of designation of such preferred stock applicable thereto, any vacancy on the Board may be filled by the Board. A stockholder intending to nominate one or more persons for election as a director at an annual or special meeting of the Board must follow the procedures set forth in the Bylaws, including provision of advance notice of such director nomination in proper written form to our Corporate Secretary. Our Bylaws also provide that all elections of directors of the Company will be determined by a plurality of the votes cast, and except as otherwise required by law or the rules of any stock exchange upon which our securities are listed or as otherwise provided in the Bylaws or the Certificate of Incorporation, all other matters will be determined by a majority of the votes cast affirmatively or negatively, on such matter.

Corporate Governance

Our Chief Executive Officer and Chief Financial Officer have each signed and filed the certifications under Section 302 of the Sarbanes-Oxley Act of 2002 with this Annual Report for the fiscal year ended December 31, 2017.

We maintain on our website, www.vnrenergy.com, copies of the charters of each of the committees of the Board, as well as copies of our Corporate Governance Guidelines; Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer; Insider Trading Policy; Code of Business Conduct and Ethics; and Related Party Transactions Policy. Copies of these documents are also available in print upon request of our Corporate Secretary. The Code of Business Conduct and Ethics provides guidance on a wide range of conduct, conflicts of interest and legal compliance issues for all of our directors, officers and employees. The Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer is designed to deter wrongdoing and promote ethical conduct, timely and accurate reporting, and compliance with laws. We will post any amendments to, or waivers of, the Code of Business Conduct and Ethics or Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer on our website.

Board Leadership Structure and Role in Risk Oversight

Mr. Citarrella, one of our independent directors, currently serves as Chairman of the Board. The Corporate Governance Guidelines adopted by our Board provide that the independent directors will meet in executive session after each regular meeting of the Board, or more frequently if necessary. As Chairman of the Board, Mr. Citarrella serves as lead independent director and chairs any non-management executive sessions of the Board.

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Committees of the Board of Directors

The standing committees of the Board currently are the audit committee (the “Audit Committee”), the compensation committee (the “Compensation Committee”), the nominating and corporate governance committee (the “N&G Committee”), the health, safety and environmental committee (“HSE Committee”) and the strategic opportunities committee (the “Strategic Opportunities Committee”).

Audit Committee

The primary responsibilities for the Audit Committee are set forth in the Audit Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The Audit Committee’s duties include assisting the Board in fulfilling its responsibility to oversee management regarding: (i) the conduct and integrity of our financial reporting to any governmental or regulatory body, the public or other users thereof; (ii) our systems of internal accounting and financial and disclosure controls; (iii) the qualifications, engagement, compensation, independence and performance of our independent auditors, their conduct of the annual audit, and their engagement for any other services; (iv) our legal and regulatory compliance; and (v) our codes of ethics as established by management and the Board.

In discharging its oversight role, the Audit Committee is authorized: (i) to investigate any matter that the Audit Committee deems appropriate, with access to all of our books, records, facilities and personnel; and (ii) to retain independent counsel, auditors or other experts.

The current members of the Audit Committee are Messrs. Dunlevy, Alexander and Morris. Mr. Dunlevy is the Chairman of the Audit Committee and has been determined by the Board to be an “audit committee financial expert,” as defined by Item 407(d) of Regulation S-K (17 C.F.R. 240.407(d)). Our Board has also determined each member of the Audit Committee is an independent director under the OTCQX requirements, as set forth in Part III, Item 13 of this Annual Report.

Compensation Committee

The primary responsibilities for the Compensation Committee are set forth in the Compensation Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The Compensation Committee determines and approves, either on its own or with our independent directors, compensation of the Chief Executive Officer and assists the Board in: (i) determining appropriate compensation levels for our other executive officers; (ii) evaluating officer and director compensation plans, policies and programs; and (iii) reviewing compensation and benefit plans for officers and employees.

In discharging its role, the Compensation Committee is empowered to investigate any matter brought to its attention with access to all of our books, records, facilities and personnel. The Compensation Committee may, in its sole discretion, select, retain or obtain the advice of independent legal counsel, compensation consultants or other advisors (collectively, “Advisors”) and will receive appropriate funding from us, as determined by the Compensation Committee, for payment of reasonable compensation to such Advisors. The Compensation Committee will be directly responsible for the appointment, compensation and oversight of the work of any Advisor retained by the Compensation Committee, who shall be accountable ultimately to the Compensation Committee. Prior to selecting an Advisor, the Compensation Committee shall assess the Advisor’s independence from our management, taking into consideration all relevant factors the Compensation Committee deems appropriate to such Advisor’s independence, including any factors specified in applicable rules and regulations. The Compensation Committee may select or receive advice from any Advisor it prefers, including Advisors that are not independent, after considering the independence factors required by applicable rules and regulations.

The current members of the Compensation Committee are Messrs. Morris, Albert and Citarrella. Mr. Morris is the Chairman of the Compensation Committee.

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Nominating and Corporate Governance Committee

The primary responsibilities for the N&G Committee are set forth in the N&G Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The purpose of the N&G Committee is to assist the Board by: (i) identifying, screening and reviewing individuals qualified to serve as directors and recommending to the Board candidates for election at the annual meeting of stockholders to fill Board vacancies; (ii) developing, recommending to the Board and overseeing implementation of our Corporate Governance Guidelines and Principles; and (iii) reviewing, on a regular basis, our overall corporate governance and recommending to the Board improvements when necessary.

In discharging its role, the N&G Committee is empowered to investigate any matter brought to its attention with access to all of our books, records, facilities and personnel. The N&G Committee has the power to retain outside counsel, director search and recruitment consultants or other experts. The N&G Committee shall have the sole authority to retain, compensate, terminate and oversee director search and recruitment consultants, who shall be accountable ultimately to the N&G Committee.

The current members of the N&G Committee are Messrs. Alexander and Citarrella. Mr. Citarrella is the Chairman of the N&G Committee.

Health, Safety and Environmental Committee

The primary responsibilities for the HSE Committee are set forth in the HSE Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The purpose of the HSE Committee is to assist the Board with its responsibilities relating to oversight of our health, safety and environmental practices and to monitor management’s efforts in creating a culture of safety and environmental protection. The HSE Committee primarily fulfills this responsibility by carrying out activities such as the following: (i) reviewing and monitoring safety and environmental protection practices and performance; (ii) assisting the Board with our risk management process and our security processes; (iii) developing annual health, safety and environmental goals and objectives; (iv) reviewing and providing input on the management of current and emerging health, safety and environmental issues; and (v) reviewing and monitoring significant regulatory audits, findings, orders, reports and/or recommendations issued by or to us related to health, safety and environmental matters.

The current members of the HSE Committee are Messrs. Albert, Citarrella, Sloan and Hurliman. Mr. Hurliman is the Chairman of the HSE Committee.

Strategic Opportunities Committee

The primary responsibilities for the Strategic Opportunities Committee are set forth in the Strategic Opportunities Committee Charter, which was adopted by the Board on August 9, 2017 and is available on our website under the “Corporate Governance” tab. The purpose of the Strategic Opportunities Committee is to assist the Board with its oversight responsibilities relating to long-term strategy for us, risks and opportunities to the strategy, and strategic decisions regarding the portfolio of business and investments. The Strategic Opportunities Committee primarily fulfills this responsibility by carrying out activities such as the following: (i) working with executive officers in the development of our strategy, recommending to the Board the annual strategic plan and long-term strategy, and providing guidance for the strategic planning process; (ii) reviewing risks and opportunities to the strategies as identified by our strategic risk assessment; (iii) monitoring our progress against strategic goals and providing feedback and advice, with particular emphasis on segment key performance indicators and strategy metrics; (iv) reviewing, considering, investigating, analyzing, evaluating, monitoring and exercising general oversight over activities involving strategic transactions; (v) making recommendations to the Board with respect to whether to authorize and approve any strategic transaction; and (vi) assisting with post-acquisition integration and business development opportunities.

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In discharging its oversight role, the Committee is authorized: (i) to investigate any matter that the Strategic Opportunities Committee deems appropriate, with access to all of our books, records, facilities and personnel; and (ii) to retain independent counsel, auditors or other experts.

The current members of the Strategic Opportunities Committee are Messrs. Alexander, Morris, Citarrella and Sloan. Mr. Alexander is the Chairman of the Strategic Opportunities Committee.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, requires our directors and executive officers, and persons who beneficially own more than 10% of a registered class of our equity securities, to file initial reports of ownership of our equity securities and reports of changes in ownership of our equity securities with the SEC. Such persons are also required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that during the fiscal year ended December 31, 2017, all Section 16(a) reporting persons complied with all applicable filing requirements in a timely manner, except that (i) Mr. Pence filed a late Form 4 on January 5, 2017 regarding the vesting of phantom units and cash received in lieu of common units of the Predecessor on January 1, 2017; (ii) Messrs. Smith, Robert and Pence filed late Form 4s on January 5, 2017 regarding the acquisition of phantom units of the Predecessor they received on January 1, 2017; (iii) Messrs. Smith, Robert and Pence filed late Form 4s on January 12, 2017 regarding the net-down of common units as a result of restricted units of the Predecessor that vested on January 1, 2017; and (iv) Contrarian, Monarch and Marathon filed late Form 4s on March 5, 2018, March 6, 2018 and March 9, 2018, respectively, regarding the acquisition of Common Stock pursuant to the terms of the Final Plan. In addition, and based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that during the fiscal quarter ended March 31, 2018 Contrarian filed a late Form 4 on March 5, 2018 regarding its acquisition of 28,500 shares of Common Stock.

Director Compensation and Indemnification of Directors and Officers

Information regarding the compensation provided to our non-employee directors is presented in “Director Compensation” beginning on page 171.

Section 145 of the Delaware General Corporation Law (the “DGCL”) permits corporations to indemnify directors and officers. The statute generally requires that to obtain indemnification, the director or officer must have acted in good faith and in a manner reasonably believed to be in or not opposed to the best interests of the corporation; and, additionally, in criminal proceedings, that the officer or director had no reasonable cause to believe his conduct was unlawful. In any proceeding by or in the right of the corporation, no indemnification may be provided if the director or officer is adjudged liable to the corporation (unless ordered by the court). Indemnification against expenses actually and reasonably incurred by a director or officer is required to the extent that such director or officer is successful on the merits in the defense of the proceeding.

Our Certificate of Incorporation provides that we will indemnify and hold harmless, to the fullest extent permitted by the DGCL, any person who was or is made or is threatened to be made a party or is otherwise involved in any threatened, pending or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, by reason of the fact that he or she is or was one of our directors or officers or is or was serving at our request as a director or officer of another corporation, partnership, joint venture, trust or other enterprise. Our Certificate of Incorporation further provides for the advancement of expenses to each of its officers and directors.

Our Certificate of Incorporation provides that, to the fullest extent permitted by the DGCL, our directors shall not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director. Under Section 102(b)(7) of the DGCL, the personal liability of a director to the corporation or its stockholders for monetary damages for breach of fiduciary duty can be limited or eliminated except (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders; (2) for any act or omission not in good faith or which involves intentional misconduct or a

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knowing violation of law; (3) under Section 174 of the DGCL (relating to unlawful payment of dividend or unlawful stock purchase or redemption); or (4) for any transaction from which the director derived an improper personal benefit.

We also maintain a general liability insurance policy which covers certain liabilities of our directors and officers arising out of claims based on acts or omissions in their capacities as directors or officers, whether or not we would have the power to indemnify such person against such liability under the DGCL or the provisions of the Certificate of Incorporation.

We have also entered into a customary indemnification agreement with each of our non-employee directors and certain of our executive officers. These agreements provide for us to indemnify such persons against certain liabilities that may arise by reason of their status or service as directors or executive officers and to advance their expenses incurred as a result of a proceeding as to which they may be indemnified. These indemnification agreements are intended to provide indemnification rights to the fullest extent permitted under applicable law and are in addition to any other rights the individual may have under our Certificate of Incorporation, Bylaws and applicable law.

Executive Officers

Certain information concerning the Company’s executive officers as of the date of this Annual Report is set forth below.



Name	Age	Position with Vanguard
R. Scott Sloan	53	President, Chief Executive Officer and Director
Ryan Midgett	33	Chief Financial Officer
Britt Pence	57	Executive Vice President of Operations
Jonathan C. Curth	35	General Counsel, Corporate Secretary and Vice President of Land

R. Scott Sloan has served as our Chief Executive Officer since January 2018. See his biographical information and his experience under “Board of Directors” included under Part III, Item 10 of this Annual Report.

Ryan Midgett has served as our Chief Financial Officer since January 2018. Mr. Midgett has over a decade of experience in financial management, analysis and reporting roles in the oil and gas industry. Prior to his appointment as the Company’s Chief Financial Officer, Mr. Midgett served as the Vice President, Finance and Treasurer of the Company since August 2016. In that role, his responsibilities included strategic planning, budgeting and forecasting, economic analysis of the Company’s organic opportunities and mergers and acquisitions transactions, overseeing and executing numerous capital markets transactions, negotiating credit agreements, overseeing the Company’s insurance and risk management program, and overseeing other corporate treasury functions. Previously, he was the Company’s Treasurer since 2013 and Assistant Treasurer since April 2011. Prior to joining the Company, Mr. Midgett served in various financial analyst, investor relations, and business development roles at Linn Energy from 2006 to 2011. Mr. Midgett received his B.A. in Economics, Managerial Studies and Political Science from Rice University.

Britt Pence has served as our Executive Vice President of Operations since January 2013. Prior to this promotion, Mr. Pence was our Senior Vice President of Operations beginning in June 2010 and Vice President of Engineering since joining the Company in May 2007. Prior to joining us, since 1997, Mr. Pence was an Area Manager with Anadarko Petroleum Corporation supervising evaluation and exploitation projects in coalbed methane fields in Wyoming and conventional fields in East Texas and the Gulf of Mexico. Prior to joining Anadarko, Mr. Pence served as a reservoir engineer with Greenhill Petroleum Company from 1991 to 1997 with responsibility for properties in the Permian Basin, South Louisiana and the Gulf of Mexico. From 1983 to 1991, Mr. Pence served as reservoir engineer with Mobil with responsibility for properties in the Permian Basin. Mr. Pence holds a B.S. in Petroleum Engineering from Texas A&M University. On January 17, 2018, Mr. Pence agreed to step down from his positions effective on or before June 29, 2018, or such other time as mutually agreed with the Company.

Jonathan C. Curth has served as our General Counsel, Corporate Secretary and Vice President of Land since December 2017. From August 2013 through December 2017, Mr. Curth served as the Assistant General Counsel at Newfield Exploration Company, where he managed upstream and midstream transactions and litigation and supported numerous departments, including land, land administration, marketing, operations, records, accounting, governmental affairs, and internal audit. Mr.

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Curth concentrated on domestic and international oil and gas transactions and operational matters at Baker & McKenzie LLP from 2011 through 2013 and at Brown & Fortunato, P.C. from August 2007 through January 2011. Mr. Curth brings over a decade of legal experience to us, with an emphasis on oil and gas transactions, in addition to experience in corporate governance matters and formulating and implementing land-related processes and procedures. He received his B.A. from Baylor University and his J.D. from The University of Texas School of Law. Mr. Curth is licensed in Texas and Oklahoma, has presented at several conferences and contributed to numerous articles and presentations, and he is Board Certified in Oil, Gas and Mineral Law by the Texas Board of Legal Specialization.

ITEM 11. EXECUTIVE COMPENSATION

Named Executive Officers

This executive compensation section provides information about our compensation objectives and policies for our named executive officers. Pursuant to the SEC rules applicable to smaller reporting companies we must provide disclosure regarding the following individuals: (i) all individuals serving as the Company’s principal executive officer or acting in a similar capacity during the last completed fiscal year; (ii) the Company’s two most highly compensated executive officers other than the principal executive officers who were serving as executive officers at the end of the last completed fiscal year; and (iii) up to two additional individuals for whom disclosure would have been provided pursuant to clause (ii) above but for the fact that the individual was not serving as an executive officer of the Company at the end of the last completed fiscal year. We refer to these executive officers in this section and the related compensation tables as the “named executive officers.” For the fiscal year ended December 31, 2017, the named executive officers were:


•	R. Scott Sloan, our former Executive Vice President and Chief Financial Officer and current President and Chief Executive Officer;


•	Britt Pence, our Executive Vice President of Operations;


•	Scott W. Smith, our former President and Chief Executive Officer; and


•	Richard A. Robert, our former Executive Vice President and Chief Financial Officer.

2017 Summary Compensation Table

The following table sets forth certain information with respect to the compensation paid to our named executive officers for the fiscal years ended December 31, 2017 and December 31, 2016.

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Name and Principal Position	Year	Salary ⁽¹⁾		Bonus ⁽²⁾		Stock Awards ⁽³⁾		Non-Equity Incentive Plan Compensation ⁽⁴⁾		All Other Compensation ⁽⁵⁾		Total
R. Scott Sloan, Current President & CEO and Former EVP & CFO	2017	$	133,384	$	127,500	$	24,375	$	—	$	8,003	$	293,262

Britt Pence,	2017	$	450,000	$	595,000	$	1,575,000	$	—	$	230,979	$	2,850,979
EVP of Operations	2016	$	440,000	$	—	$	1,539,998	$	632,500	$	15,900	$	2,628,398

Scott W. Smith,	2017	$	650,000	$	717,969	$	3,575,000	$	—	$	553,565	$	5,496,534
Former President & CEO	2016	$	600,000	$	—	$	3,300,001	$	862,500	$	15,900	$	4,778,401

Richard A. Robert,	2017	$	408,333	$	464,272	$	1,960,000	$	—	$	1,566,885	$	4,399,490
Former EVP & CFO	2016	$	470,000	$	—	$	1,879,999	$	675,625	$	15,900	$	3,041,524


(1)	Fiscal year 2017 salaries presented for Messrs. Robert and Sloan are prorated for their service as principal financial officer from January 1, 2017 to September 26, 2017, and from September 26, 2017 to December 31, 2017, respectively. Mr. Sloan also received $19,361 in fees earned or paid in cash for his service as a non-employee director from August 1, 2017 until September 26, 2017.

(2)

With respect to Messrs. Smith, Robert and Pence, the 2017 bonus represents amounts accrued under the Predecessor’s Employment Agreements (as defined below), which were in effect prior to the Effective Date. Such payment includes a quarterly bonus accrued with respect to the fiscal quarters ended December 31, 2016, March 31, 2017 and June 30, 2017 but was not payable until after the Effective Date.

(3)

The amounts in this column reflect the aggregate grant date fair value, computed as of the grant date in accordance with FASB ASC Topic 718-Compensation - Stock Compensation. The equity awards granted to Messrs. Smith, Robert and Pence in 2017 were phantom unit awards granted on January 1, 2017 with respect to the 2016 performance year. In connection with the implementation of the Plan, all awards of the Predecessor’s equity were canceled as of the Effective Date. On October 31, 2017, Mr. Sloan received a stock award of 1,250 fully-vested RSUs, valued at $19.50 per share, in connection with his service as a non-employee director from August 1, 2017 until September 26, 2017.


(4)	Represents amounts paid for 2016 pursuant to our Predecessor’s annual cash incentive program with respect to the Adjusted EBITDA Results, Production Results, Lease Operating Expenses and Cash General & Administrative components.

(5)

Amount shown for Mr. Sloan in 2017 and other named executive officers in 2016 is the amount received in the form of matching contributions to our 401(k) Plan. With respect to Mr. Smith the 2017 other compensation amount is attributable to $537,365 in accrued distributions paid on unvested restricted and phantom unit awards and $16,200 in matching 401(k) contributions. With respect to Mr. Pence the 2017 other compensation amount is attributable to $214,779 in accrued distributions paid on unvested restricted and phantom unit awards and $16,200 in matching 401(k) contributions. With respect to Mr. Robert the 2017 other compensation amount is attributable to $1,225,000 in severance pay, $18,846 in accrued vacation, $306,839 in accrued distributions paid on unvested restricted and phantom unit awards and $16,200 in matching 401(k) contributions.

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Narrative Disclosure to Summary Compensation Table: Description of Employment Agreements

Certain terms of our named executive officers’ compensation are governed by employment agreements. We believe that these employment agreements assist us in attracting and retaining talented and dedicated executives by clearly setting forth the terms of employment and providing certainty to both parties. We maintain employment agreements with our named executive officers to ensure they will perform their roles for an extended period of time. These agreements include provisions for payments at, following or in connection with a change in control or resignation, retirement or other termination.

Predecessor Employment Agreements

Pursuant to the Predecessor Employment Agreements (i) Mr. Smith was entitled to an annual base salary of $650,000, (ii) Mr. Robert was entitled to an annual base salary of $490,000 and (iii) Mr. Pence was entitled to an annual base salary of $450,000. In addition, the Predecessor’s Board of Directors had the discretion to increase the base salaries of Messrs. Smith, Robert and Pence at any time. Under the Predecessor Employment Agreements, the executives were eligible to receive an annual performance-based cash bonus award, based on four company performance components (adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses), and the Board had the ability to apply a discretionary multiplier to the overall bonus targets of the four components. The four components each individually comprised 25% of the aggregate annual bonus. The annual bonus was to be calculated on a cumulative basis for each of the four components and paid out on a quarterly basis. The annual bonus was not subject to a minimum payout, while the maximum payout was not to exceed two (2) times the respective executive’s annual base salary.

Under the Predecessor Employment Agreements, the executives were also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units, under the Predecessor’s Long-Term Incentive Plan (the “Predecessor LTIP”). Mr. Smith was eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to five and a half (5.5) times his then-current annual base salary, Mr. Robert was eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to four (4) times his then-current annual base salary and Mr. Pence was eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to three and a half (3.5) times his then-current annual base salary. The Predecessor Employment Agreements also provided that Messrs. Smith, Robert and Pence were eligible to participate in the benefit programs generally available to senior executives of VNR Holdings.

Post-Emergence Employment Agreements

On the Effective Date, the Company entered into amended and restated employment agreements (the “Post-Emergence Employment Agreements”) with each of Messrs. Smith, Robert, and Pence (each, a “Post-Emergence Executive” and collectively, the “Post-Emergence Executives”). The Post-Emergence Employment Agreements were effective on the Effective Date and superseded the prior agreements referenced above. The Post-Emergence Employment Agreements provided that (i) Mr. Smith was entitled to an annual base salary of $650,000, which increased to $700,000 on January 1, 2018; (ii) Mr. Robert was entitled to an annual base salary of $490,000 and (iii) Mr. Pence is entitled to an annual base salary of $450,000, which increased to $460,000 on January 1, 2018.

Each Post-Emergence Executive is (or was, as applicable) eligible to receive an annual bonus in an amount to be determined by the Board or the Compensation Committee. Furthermore, within five (5) business days of the Effective Date, the Post-Emergence Executives were entitled to 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

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$428,595 for Mr. Pence. Each Post-Emergence Executive was eligible to receive bonus payments through the year ended December 31, 2017 in accordance with our Predecessor’s 2017 pre-emergence annual cash bonus program.

Under the Post-Emergence Employment Agreements, the Post-Emergence Executives were entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by the Company without Cause or termination by any such Post-Emergence Executive for Good Reason (each as defined in the Post-Emergence Employment Agreement) (and except with respect to a Change of Control within a year of the Effective Date), the Post-Emergence Executive is (or was, as applicable) 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 Post-Emergence Executive’s then-current base salary. As a condition to receiving any of the severance payments and benefits provided in the Post-Emergence Employment Agreements, the terminated Post-Emergence Executive (or his legal representative, as applicable) was required to execute and not revoke a customary severance and release agreement, including a waiver of all claims.

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

Mr. Robert resigned from his position with the Company on September 26, 2017. Mr. Smith stepped down from his position with the Company on January 15, 2018, while remaining with the Company to assist in the transition of his role until February 16, 2018. In connection with each of Messrs. Smith’s and Robert’s departures, the Company honored their respective Post-Emergence Employment Agreement. Mr. Pence agreed on January 17, 2018, that he would resign from the Company effective on or before June 29, 2018, or such other time as mutually agreed with the Company (the period of Mr. Pence’s continued employment, the “Transition Period”). Mr. Pence will continue to receive his current annual base salary. In addition, unless Mr. Pence resigns from employment prior to the end of the Transition Period, Mr. Pence will be eligible to receive a pro-rated portion of his target annual bonus for his service during 2018. If the Company terminates Mr. Pence’s employment without “cause” (as such term is used in Post-Emergence Employment Agreement) prior to the end of the Transition Period, then the Company will continue to pay Mr. Pence his annual base salary and his pro-rated target annual bonus through the end of the Transition Period.

Predecessor Restricted Unit Agreement and Phantom Unit Agreement

In connection with the entry into the Predecessor Employment Agreements, the Predecessor entered into restricted unit agreements and phantom unit agreements with the Predecessor Executives, subject to the terms of the Predecessor LTIP.

The restricted unit agreements were subject to a restricted period of three years. One-third of the aggregate number of the units vested on each one-year anniversary of the date of grant so long as the Predecessor Executive remained continuously employed with the Predecessor. The restricted units included a tandem grant of distribution equivalent rights (“DERs”), which entitled the Predecessor Executives to receive the value of any distributions made by the Predecessor on its units generally with respect to the number of restricted units that the each of the Predecessor Executives received pursuant to his grant. Fifty percent (50%) of the DERs were to be paid at the time any such distributions were declared and paid by the Predecessor, and the balance of the DERs was subject to the same vesting requirements as the underlying restricted units.

The phantom units were also subject to a three-year vesting period. One-third of the aggregate number of the units vested on each one-year anniversary of the date of grant so long as the Predecessor Executive remained continuously employed with the Predecessor. The phantom units included a tandem grant of DERs, which entitle the executives to receive the value of any distributions made by the Predecessor on its units generally with respect to the number of phantom units that the Predecessor Executives received pursuant to the grant. Fifty percent (50%) of the DERs were to be paid at the time any such distributions were declared and paid by the Company, and the balance of the DERs was subject to the same vesting requirements as the underlying phantom units.

The restricted unit agreements and phantom unit agreements also provided for vesting upon the Predecessor’s Change of Control (as defined in the Predecessor Employment Agreements) and payments and benefits upon certain qualifying terminations.

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On the Effective Date, in connection with the Company’s emergence from the Chapter 11 Filings, all of the Predecessor’s equity was canceled.

Vanguard Natural Resources, Inc. 2017 Management Incentive Plan

On August 22, 2017, the Compensation Committee recommended the approval of, and the Board approved, the MIP to assist the Company in attracting, motivating and retaining key personnel and to align the interests of participants with those of stockholders. The maximum number of shares of Common Stock available for issuance under the MIP is 2,233,333 shares. Employees, directors, and consultants of the Company and its subsidiaries are eligible to receive awards of stock options, restricted stock, restricted stock units or other stock-based awards at the discretion of the Compensation Committee or its designee.

On January 17, 2018, the Board approved the initial long-term incentive program under the MIP (the “LTIP”). The Company granted time-based and performance-based restricted stock unit awards as part of the LTIP to certain Company executives. The time-based restricted stock unit awards under the LTIP generally vest 1/3 on each of the first three anniversaries of October 30, 2017. The performance-based restricted stock unit awards under the LTIP are generally eligible to vest based on the Company’s total shareholder return relative to an index of its peers during the period from January 1, 2018 through December 31, 2020, and may generally range from 0% to 200% of the target amount.

Sloan Employment Agreement

The Sloan Employment Agreement provides that Mr. Sloan is entitled to an annual base salary of $510,000. In addition, the Board has the discretion to increase Mr. Sloan’s base salary, at any time if it deems an increase is warranted. Subject to certain terms and conditions, the Board may not reduce Mr. Sloan’s base salary without his prior written approval.

Mr. Sloan is eligible to receive an annual performance-based cash bonus award in an amount to be determined by the Board or Compensation Committee and equal to no less than 80% of his base salary. With respect to his employment in 2017, Mr. Sloan is entitled to receive an annual bonus in an amount not less than $127,500, payable on or before March 15, 2018. Mr. Sloan is also eligible to participate in the MIP in accordance with the terms determined by the Board. Furthermore, Mr. Sloan is eligible to participate in the benefit programs generally available to senior executives of the Company.

In the event of the Company’s Change in Control (as defined in the Sloan Employment Agreement), Mr. Sloan is entitled to certain change in control payments and benefits under the Sloan Employment Agreement. If, during the twelve (12) months immediately following the occurrence of a Change of Control of the Company, Mr. Sloan is terminated by the Company without Cause or resigns for Good Reason (each as defined in the Sloan Employment Agreement), Mr. Sloan will be entitled to receive within ten (10) business days after the date of his termination, accrued compensation and reimbursements listed in the Sloan Employment Agreement; (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; (iii) any unvested awards under the MIP will immediately vest (assuming achievement at target for any performance-based awards); (iv) any Earned but Unpaid Bonus; and (v) the Pro Rata Bonus (each as defined in the Sloan Employment Agreement). However, notwithstanding (i) through (v), if a Change of Control occurs during 2018, the payment to Mr. Sloan described in clause (ii) above will be two (2) times the sum of his base salary and target bonus for 2018. The agreement provides for the reduction of any Change of Control payments to Mr. Sloan to the extent necessary to ensure that he will not receive “excess parachute payments” under Section 280G of the Internal Revenue Code, which would result in the imposition of an excise tax to him and a loss of deduction to the Company.

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Under the Sloan Employment Agreement, Mr. Sloan is entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by the Company without Cause or termination by Mr. Sloan for Good Reason (each as defined in the Sloan Employment Agreement) (and except with respect to a Change of Control, as described above), he is entitled to receive on the sixtieth (60th) day following the date of termination, a lump sum payment of (i) an amount equal to two and a half (2.5) times his then-current base salary; (ii) the Earned but Unpaid Bonus; and (iii) the Pro Rata Bonus. Upon his termination by Disability (as defined in the Sloan Employment Agreement) or death, Mr. Sloan is entitled to accrued compensation, his Earned but Unpaid Bonus, and reimbursements. As a condition to receiving any of the Change of Control or severance payments and benefits provided in the Sloan Employment Agreement, Mr. Sloan (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.

The Sloan Employment Agreement contains standard non-competition, non-solicitation and confidentiality provisions.

The foregoing description of the Sloan Employment Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of such agreement, copy of which is attached as exhibit hereto and is incorporated herein by reference.

The Sloan Employment Agreement was amended and restated on January 17, 2018 (the “Amended and Restated Sloan Agreement”). The Amended and Restated Sloan Agreement is generally consistent with the Sloan Employment Agreement, except that the Amended and Restated Sloan Agreement is updated to reflect Mr. Sloan’s position of President and Chief Executive Officer, as well as (i) his annual base salary of $700,000, (ii) his target annual performance-based bonus award equal to 100% of his annual base salary, and (iii) the amount of his initial equity grant.

Outstanding Equity Awards at December 31, 2017

The following table provides the number and value of outstanding equity awards held by our named executive officers as of December 31, 2017:



	Stock Awards
Name	Number of Unvested Shares or Units of Stock	Market Value of Unvested Shares or Units of Stock ($)
Scott W. Smith ⁽¹⁾	—	$	—

R. Scott Sloan	—	$	—

Richard A. Robert ⁽¹⁾	—	$	—

Britt Pence ⁽¹⁾	—	$	—

(1) On the Effective Date, in connection with the Company’s emergence from the Chapter 11 Filings, all of the Predecessor’s equity previously issued to Messrs. Smith, Robert and Pence was canceled.

Director Compensation

We use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on our Board. In setting independent director compensation, we consider the significant amount of time that directors expend in fulfilling their duties to us, as well as the skill-level required by us of members of our Board. Following emergence from the Chapter 11 Filings, our non-employee directors are eligible to receive (i) an annual cash retainer of $100,000, which is paid quarterly in arrears and (ii) an annual equity grant of restricted stock units with a $100,000 grant date value, with 25% of such initial grant vesting immediately and the remainder vesting ratably on the first three anniversaries of the grant date. For 2017, the

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value at the time of the Company’s emergence from Chapter 11 was used for purposes of determining the number of restricted stock units awarded to the applicable directors. For certain non-employee directors, specifically Messrs. Citarrella, Alexander and Morris, the director’s compensation is paid to the fund that currently employs such individual (i.e., Monarch, Marathon and Contrarian, respectively) and the Board has approved that such director’s equity compensation be paid in cash in lieu of equity on the dates that such grants would have otherwise vested (i.e., 25% immediately and 25% on each of the first three anniversaries of August 1, 2017). The Board intends that future annual equity retainers will vest ratably on the first four anniversaries of the date of grant. Mr. Sloan received a pro rata portion of his equity and cash compensation in respect of his service on the Board prior to his appointment as Executive Vice President and Chief Financial Officer. Mr. Dunlevy receives an additional annual cash retainer of $25,000 for his service as Chairman of the Audit Committee.

Each member of our Board is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or committees. We maintain a D&O insurance policy for the benefit of the Board and provide indemnification pursuant to our standard form of Indemnification Agreement. See Part III, Item 10 of this Annual Report for a description of our indemnification policies with respect to the Board.

2017 Director Compensation Table

The table below summarizes the compensation paid by us to our independent directors for the fiscal year ended December 31, 2017.



Name ⁽¹⁾	Fees Earned or Paid in Cash ($)		Stock Awards ($)		Total ($)
Predecessor Board of Directors Pre-Emergence
W. Richard Anderson ⁽²⁾	$	93,750	$	157,718	$	251,468
Bruce W. McCullough ⁽²⁾	$	93,750	$	157,718	$	251,468
Loren Singletary ⁽²⁾	$	93,750	$	157,718	$	251,468

Board Post-Emergence
Joseph Citarrella ⁽³⁾	$	50,000	$	—	$	50,000
Randall Albert ⁽⁴⁾	$	25,000	$	97,500	$	122,500
Michael Alexander ⁽⁵⁾	$	50,000	$	—	$	50,000
W. Greg Dunlevy ⁽⁶⁾	$	31,250	$	97,500	$	128,750
Graham Morris ⁽⁷⁾	$	50,000	$	—	$	50,000

(1)

Messrs. Smith and Robert are not included in this table as they were also executive officers of the Predecessor and Successor and received no additional compensation for their service as directors. All compensation provided to or earned by Messrs. Smith and Robert for 2017 is reported in the Summary Compensation Table above. Certain compensation that Mr. Sloan received in respect of his service as a director is included in the Summary Compensation Table above.

(2)

Messrs. Anderson, McCullough and Singletary received prorated compensation of $125,000 in fees for their service as directors from January 1, 2017 to July 31, 2017. Messrs. Anderson, McCullough and Singletary each held 41,946 unvested phantom units, which became 100% vested on January 4, 2017. Upon vesting, Messrs. Anderson, McCullough and Singletary each received a cash payment totaling $32,717.88, the fair market value of the phantom units, based on the January 3, 2017 closing price of $0.78 per unit. Additionally, Messrs. Anderson, McCullough and Singletary each were granted phantom unit awards on January 4, 2017. Any equity issued by the Predecessor as compensation to the Predecessor’s Board of Directors was canceled effective as of August 1, 2017.


(3)	Mr. Citarrella is not personally compensated for his services on the Board; rather, his compensation is passed to Monarch, his employer, if and as applicable to his role in the determination of the Board. Following the Effective Date, Monarch received approximately $50,000 in connection with Mr. Citarrella’s service as a director and as Chairman of the N&G Committee.


(4)	Mr. Albert received $25,000 for his service as non-management director from September 26, 2017 through December 31, 2017. He also received 5,000 RSUs, valued at $19.50 per share, pursuant to the MIP. Each RSU represents the right to receive one share of Common Stock. 25% of the

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RSUs vested on the Grant Date, October 31, 2017. The remaining RSUs shall vest ratably on the first three anniversaries of the Grant Date. Settlement of RSUs will be at the earliest of: (i) Mr. Albert’s termination of service or (ii) a change in control event.


(5)	Mr. Alexander is not personally compensated for his services on the Board; rather, his compensation is passed to Marathon, his employer, if and as applicable to his role in the determination of the Board. Following the Effective Date, Monarch received approximately $50,000 in connection with Mr. Alexander’s service as a director and as Chairman of the Strategic Opportunities Committee.

(6)

Mr. Dunlevy received $31,250 for his service as non-management director and as the Chairman of the Audit Committee from October 16, 2017 through December 31, 2017. He also received 5,000 RSUs, valued at $19.50 per share, pursuant to the MIP. Each RSU represents the right to receive one share of Common Stock. 25% of the RSUs vested on the Grant Date, October 31, 2017. The remaining RSUs shall vest ratably on the first three anniversaries of the Grant Date. Settlement of RSUs will be at the earliest of: (i) Mr. Dunlevy’s termination of service or (ii) a change in control event.


(7)	Mr. Morris is not personally compensated for his services on the Board; rather, his compensation is passed to Contrarian, his employer, if and as applicable to his role in the determination of the Board. Following the Effective Date, Monarch received approximately $50,000 in connection with Mr. Morris’s service as a director and as Chairman of the Compensation Committee.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plan Information

The following table provides information as of December 31, 2017, regarding securities authorized for issuance under the Company’s equity compensation plans, including the MIP.



Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights			(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Previously Approved by Stockholders: Stock Plan		—		$	—		—
Not Previously Approved by Stockholders:		11,250	⁽¹⁾	$	—		2,222,083	⁽²⁾


(1)	This amount includes 11,250 deferred restricted stock units under the MIP. The subject shares are not included in the calculation in column (b) as the weighted-average exercise price of outstanding options, warrants, and rights in column (b) does not take restricted shares, restricted stock units, or other non-option awards into account.


(2)	The share reserve authorized for issuance under the MIP was approved by the Bankruptcy Court in connection with the Plan.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth, as of March 7, 2018, the number of shares of our equity securities beneficially owned by (i) each person known by us to be the holder of more than five percent of our voting securities, (ii) each director, (iii) each named executive officer, and (iv) all of our directors and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the SEC under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Common Stock subject to currently exercisable and convertible securities, which are exercisable or convertible within 60 days after the date of March 7, 2018, are deemed outstanding for purposes of computing the percentage beneficially

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owned by the person or entity holding such securities but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person or entity. Unless otherwise indicated, each holder has sole voting and investment power with respect to the Common Stock owned by such holder.



Name of Beneficial Owner	Shares	Percent of Class

5% Owners
Marathon Asset Management, L.P.⁽¹⁾	4,958,230	24.7	%
Contrarian Capital Management, L.L.C.⁽²⁾	3,266,141	16.2	%
Morgan Stanley & Co. LLC⁽³⁾	2,210,042	11.0	%
Monarch Alternative Capital LP⁽⁴⁾	2,045,773	10.2	%
J.P. Morgan Securities LLC⁽⁵⁾	1,468,528	7.3	%
FMR LLC⁽⁶⁾	1,209,218	6.0	%

Directors
Randall M. Albert	1,250 ⁽⁷⁾	*
Michael Alexander	—	—
Joseph Citarrella	—	—
W. Greg Dunlevy	1,250 ⁽⁸⁾	*
Graham Morris	—	—
Joseph Hurliman Jr.	—	—

Named Executive Officers
R. Scott Sloan	1,250 ⁽⁹⁾	*
Britt Pence	—	—
Richard A. Robert	—	—
Scott W. Smith	—	—

All directors and executive officers as a group (13 persons)	3,750	*	%

* Less than 1%.

(1)

Bruce Richards and Louis Hanover, are managing members of Marathon Asset Management GP LLC, general partner of Marathon, which acts as investment advisor to certain funds and accounts. Michael V. Alexander, an employee of Marathon and/or one of its affiliates, is a member of the Board. Mr. Alexander does not individually hold or otherwise beneficially own any securities of Vanguard Natural Resources, Inc. Mr. Alexander disclaims beneficial ownership of any such securities, except to the extent of his pecuniary interest therein. The number of shares beneficially owned includes 2,646 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Bluegrass Credit Fund LP, 8,220 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Centre Street Partnership, 2,850 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Credit Dislocation Fund LP, 14,154 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Marathon Special Opportunity Master Fund LTD, 2,080 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Master SIF SICAV-SIF, and 3,237 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by TRS Credit Fund LP that, in each case, are exercisable within 60 days of March 7, 2018. The business address of these funds and accounts is One Bryant Park, 38th Floor, New York, NY 10036.


(2)	Contrarian is the general partner of Contrarian Advantage-B, LP (“TCAB”). The managing member of Contrarian is Mr. Jon R. Bauer (“Bauer”) and each of Contrarian and Bauer may be deemed to beneficially own the securities held by TCAB. Contrarian and Bauer each disclaim beneficial ownership of such securities except to the extent of their

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pecuniary interests therein. Graham Morris, an employee of Contrarian, is a member of the Board. Mr. Morris disclaims beneficial ownership of such securities. The business address of TCAB is 411 West Putnam Ave, Ste 425, Greenwich, CT 06830.

Contrarian is the investment manager for Contrarian Capital Trade Claims, L.P. (“CCTC”), Contrarian Capital Senior Secured, L.P. (“CSSM”), Contrarian Distressed Equity, L.P. (“CDE”), Contrarian Opportunity Fund L.P. (“COF”), Contrarian Centre Street Partnership, L.P. (“CCSP”), Contrarian Dome du Gouter Master Fund, LP (“CDGM”) and Contrarian Capital Fund I, L.P. (“CCI”). The managing member of Contrarian is Bauer and each of Contrarian and Bauer may be deemed to beneficially own the securities held by CCTC, CSSM, CDE, COF, CCSP, CDGM and CCI. Contrarian and Bauer each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. Graham Morris, an employee of Contrarian, is a member of the Board. Mr. Morris disclaims disclaims beneficial ownership of such securities. The business address of CCTC, CSSM, CDE, COF, CCSP, CDGM and CCI is 411 West Putnam Ave, Ste 425, Greenwich, CT 06830.

Contrarian is the managing member of CCM Pension-A, L.L.C. (“CPENA”) and CCM Pension-B, L.L.C. (“CPENB”). The managing member of Contrarian is Bauer and each of Contrarian and Bauer may be deemed to beneficially own the securities held by CPENA and CPENB. Contrarian and Bauer each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. Graham Morris, an employee of Contrarian, is a member of the Board. Mr. Morris disclaims beneficial ownership of such securities. The business address of CPENA and CPENB is 411 West Putnam Ave, Ste 425, Greenwich, CT 06830.

(3)

Richard VanderMass is a Managing Director of the business unit at Morgan Stanley & Co. LLC that holds the shares in the ordinary course of its business and as such may be deemed to have voting and dispositive power over the shares held by Morgan Stanley & Co. LLC. Richard VanderMass disclaims beneficial ownership of these shares. Morgan Stanley & Co. LLC, a registered broker-dealer, is a subsidiary of Morgan Stanley, a widely held reporting company under the Exchange Act. The number of shares beneficially owned includes 1,507 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by Morgan Stanley that are exercisable within 60 days of March 7, 2018. The mailing address for Morgan Stanley & Co. LLC is 1585 Broadway, 2nd Floor, New York, NY 10036.

(4)

Monarch is the investment manager for Monarch Alternative Solutions Master Fund Ltd, Monarch Capital Master Partners III LP, MCP Holdings Master LP, Monarch Debt Recovery Master Fund Ltd and P Monarch Recovery Ltd. (together, the “Monarch Funds”). MDRA GP LP (“MDRA”) is the general partner of Monarch. Monarch GP LLC (“Monarch GP”) is the general partner of MDRA. Monarch, MDRA and Monarch GP each may be deemed to beneficially own the securities held by the Monarch Funds. Monarch, MDRA and Monarch GP each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. Joseph Citarrella, a Managing Principle of Monarch, is a member of the Board. Mr. Citarrella disclaims beneficial ownership of any such securities. The business address for each of the Monarch Funds is c/o Monarch Alternative Capital LP, 535 Madison Avenue, New York, NY 10022.

(5)

Each of Christopher L. Harvey, Eric D. Tepper, Eric J. Stein, Jason Edwin Sippel, Kelly Cesare Coffey, Matthew Cherwin, Patrick C. Kirby and Robert C. Holmes is a Manager of J.P. Morgan Securities LLC (“JPM”), a Delaware limited liability company, and as such may be deemed to have voting and dispositive power over the shares held by JPM. Each of Christopher L. Harvey, Eric D. Tepper, Eric J. Stein, Jason Edwin Sippel, Kelly Cesare Coffey, Matthew Cherwin, Patrick C. Kirby and Robert C. Holmes disclaims beneficial ownership of the shares. JPM is a broker-dealer registered pursuant to Section 15 of the Exchange Act. The number of shares beneficially owned includes 53,707 shares of Common Stock issuable upon exercise of Preferred Unit Warrants held by JPM that are exercisable within 60 days of March 7, 2018. The business address for each of JPM, Christopher L. Harvey, Eric D. Tepper, Eric J. Stein, Jason Edwin Sippel, Kelly Cesare Coffey, Matthew Cherwin, Patrick C. Kirby and Robert C. Holmes is 383 Madison Avenue, 3rd Floor, New York, New York 10179.

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(6)

Reflects accounts managed by direct or indirect subsidiaries of FMR LLC. Abigail P. Johnson is a Director, the Vice Chairman, the Chief Executive Officer and the President of FMR LLC. Members of the Johnson family, including Abigail P. Johnson, are the predominant owners, directly or through trusts, of Series B voting common shares of FMR LLC, representing 49% of the voting power of FMR LLC. The Johnson family group and all other Series B shareholders have entered into a shareholders’ voting agreement under which all Series B voting common shares will be voted in accordance with the majority vote of Series B voting common shares. Accordingly, through their ownership of voting common shares and the execution of the shareholders’ voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR LLC. Neither FMR LLC nor Abigail P. Johnson has the sole power to vote or direct the voting of the shares owned directly by the various investment companies registered under the Investment Company Act (“Fidelity Funds”) advised by Fidelity Management & Research Company (“FMR Co”), a wholly owned subsidiary of FMR LLC, which power resides with the Fidelity Funds’ Boards of Trustees. Fidelity Management & Research Company carries out the voting of the shares under written guidelines established by the Fidelity Funds’ Boards of Trustees. The business address of Fidelity Summer Street Trust: Fidelity Capital & Income Fund, Variable Insurance Products Fund: Strategic Income Portfolio, Fidelity School Street Trust: Fidelity Strategic Income Fund and Fidelity Advisor Series II: Fidelity Advisor Strategic Income Fund are 245 Summer Street, Boston, MA 02210. The Fidelity Funds are affiliates of a registered broker-dealer.


(7)	Comprised of 1,250 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of March 7, 2018, upon any departure from the Board.


(8)	Comprised of 1,250 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of March 7, 2018, upon any departure from the Board.


(9)	Comprised of 1,250 shares of Common Stock subject to vested deferred RSUs that may become issuable within 60 days of March 7, 2018, upon any departure from the Board.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Director Independence

We do not have any securities listed for trading on a national securities exchange, but our Common Stock is quoted on the OTCQX. As a member of the OTCQX, we are subject to the OTCQX Rules for U.S. Companies, which requires that we have at least two independent directors. Under the OTCQX Rules for U.S. Companies, an independent director is defined as any person other than an executive officer or employee of the Company or any other individual having a relationship which, in the opinion of the Board, would interfere with the exercise of independent judgment in carrying out responsibilities as a director. For purposes of complying with the OTCQX requirements, our Board has determined that each of Messrs. Albert, Alexander, Citarrella, Dunlevy, Hurliman and Morris qualifies as an independent director.

Review, Approval or Ratification of Transactions with Related Persons

On August 9, 2017 the Board adopted the Related Party Transaction Policy (the “Policy”) to review and approve all Related Transactions with Related Parties, as those terms are defined in the Policy and as set forth below.

Prior to the entry of any potential Related Transaction, such transaction shall be reported to our General Counsel or, if there is no General Counsel, the Chairman of the Audit Committee, who will undertake an appropriate evaluation to determine if the counterparty in the transaction meets the definition of a Related Party. If that evaluation indicates that the Related Transaction would require the Audit Committee’s approval, the General Counsel or, if there is no General Counsel, the Chairman of the Audit Committee, will report the Related Transaction, together with a summary of material facts, to the Audit Committee. The Audit Committee shall review the material facts of the Related Transaction and either approve or disapprove subject to the exceptions described below. In determining whether to approve or disapprove a Related Transaction, the Audit Committee will

162

consider whether there is a relationship that offers the potential for: (i) transactions at less than arm’s-length; (ii) favorable treatment; or (iii) the ability to influence the outcome of events differently from that which might result in the absence of that relationship.

In the event our Chief Executive Officer, Chief Financial Officer or General Counsel becomes aware of a Related Transaction that was not previously approved under the Policy, such person shall promptly notify the Chairman of the Audit Committee, and the Audit Committee or, if not practicable for us to wait for the entire Audit Committee to consider the matter, the Chairman of the Audit Committee shall consider whether the Related Transaction shall be ratified or rescinded or other action should be taken. The Chairman of the Audit Committee shall report to the Audit Committee at the next Audit Committee meeting any actions taken under the Policy.

The Audit Committee has already reviewed certain Related Transactions as described as in the Policy and determined that each of the Related Transactions described therein shall be deemed to be pre-approved or ratified, as applicable, by the Audit Committee under the terms of the Policy, unless specifically determined otherwise by the Audit Committee.

No director shall participate in any discussion or approval of a Related Transaction for which he or she is a Related Party, except that the director shall provide all material information concerning the Related Transaction to the Audit Committee.

For purposes of the Policy, a Related Party transaction is defined as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships in excess of $120,000, in which we or any of our subsidiaries is a participant, and any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director, officer or a less than ten percent beneficial owner of another entity).

For purposes of the Policy a “Related Party” is defined as any person who is or was (since the last fiscal year for which we have filed an Annual Report, even if that person does not presently serve in that role):


•	an affiliate of us - a party that, directly or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with us;


•	a trust for the benefit of employees that is managed by or under the trusteeship of management;


•	an owner of record or known beneficial owner of more than 5% of the voting interest of us;

•

a member of our management including people with authority and responsibility for planning, directing and controlling our activities. Management includes members of the Board, Chief Executive Officer, Chief Financial Officer, General Counsel, Vice Presidents and persons in charge of principal business units and business functions, and any other persons who perform similar business or policymaking functions. If a director or member of management is also a director of another entity, the entities are considered related when they are both under the control or significant influence of that individual;


•	any family member, including spouses, brothers, sisters, parents, children and spouses of these persons who might control or influence a principal owner or member of management or who might be controlled or influenced by a principal owner or member of management because of a family relationship; or

•

other parties with which we may deal if one party can control or significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests. The ability to exercise significant influence may be indicated in several ways, such as representation on the Board, participating in policy-making processes, material inter-company transactions, interchange of managerial personnel, or technology dependency.

Registration Rights Agreement

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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 the Registration Rights Agreement with the Registration Rights Holders, in accordance with the terms set forth in the Plan. The Registration Rights Agreement provides our stockholders party thereto certain registration rights.

The Registration Rights Agreement requires the Company to file the 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 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 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.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Our Predecessor’s audit committee engaged BDO USA, LLP (“BDO”) to serve as our independent registered public accounting firm for the fiscal years ended December 31, 2017 and December 31, 2016.

Audit Fees. Audit fees charged by BDO (“Audit Fees”) represent fees for professional services provided by our principal accountant in connection with the audit of our annual financial statements included in our annual reports for the years ended December 31, 2017 and December 31, 2016 and of management’s assessment and the effectiveness of internal control over financial reporting included in our annual report for the year ended December 31, 2016, the quarterly reviews of financial statements included in our Form 10-Q filings and other statutory or regulatory filings. For the years ended December 31, 2017 and December 31, 2016, we paid BDO Audit Fees in the amount of $627,000 and $542,750, respectively.

Audit-Related Fees. Audit-related fees charged by BDO (“Audit-Related Fees”) are fees for assurance and related services that are reasonably related to the performance by our principal accountant of the audit or review of our financial statements that are not Audit Fees. Previously BDO received fees for audits of acquisition-related financial statements. There were no Audit-Related Fees for the years ended December 31, 2017 and December 31, 2016.

Tax Fees. Tax fees charged by BDO (“Tax Fees”) include professional services performed by our principal accountant for tax compliance, tax advice and tax planning. There were no Tax Fees for the years ended December 31, 2017 or 2016.

All Other Fees. All Other Fees includes the aggregate fees for products and services provided by our principal accountant that are not reported under “Audit Fees,” “Audit-Related Fees” or “Tax Fees.” There were no Other Fees for the years ended December 31, 2017 or December 31, 2016.

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Audit Committee Pre-Approval Policies and Practices

The Audit Committee pre-approves all services provided to the Company and its subsidiaries by BDO. The Audit Committee has adopted a schedule for annual approval of the audit and related audit plan, as well as approval of other anticipated audit-related services; anticipated tax compliance, tax planning and tax advisory services; and other anticipated services. In addition, the Audit Committee (or an authorized committee member acting under delegated authority of the Audit Committee) will consider any proposed services not approved as part of this annual process. For the years ended December 31, 2017 and December 31, 2016, all audit and non-audit services were pre-approved by the Audit Committee.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

Financial statements

The following consolidated financial statements are included in Part II, Item 8 of this Annual Report:



	Page
Report of Independent Registered Public Accounting Firm	89
Consolidated Statements of Operations	90
Consolidated Balance Sheets	91
Consolidated Statements of Stockholders’/Members’ Equity (Deficit)	92
Consolidated Statements of Cash Flows	93
Notes to Consolidated Financial Statements	95
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)	137
Supplemental Oil and Natural Gas Information	139

(b) Exhibits

The following exhibits are incorporated by reference into the filing indicated or are filed herewith.



Exhibit Number		Description of Exhibit
2.1		Modified Second Amended Joint Plan of Reorganization under Chapter 11 of Bankruptcy Code of Vanguard Natural Resources, LLC (incorporated by reference to Exhibit 2.1 to our Predecessor’s Current Report on Form 8-K filed July 19, 2017)
3.1		Amended and Restated Certificate of Incorporation of Vanguard Natural Resources, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
3.2		Amended and Restated Bylaws of Vanguard Natural Resources, Inc. (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K15D5 filed August 2, 2017)
3.3		Certificate of Amendment as filed with the Delaware Secretary of State (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed September 29, 2017)
4.1		Amended and Restated Indenture, dated as of August 1, 2017, among Vanguard Natural Resources, Inc., the guarantors named therein and Delaware Trust Company, as trustee and collateral trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.1		Fourth Amended and Restated Credit Agreement, dated as of August 1, 2017, by and among Vanguard Natural Gas, LLC, Citibank N.A., as Administrative Agent and the financial institutions thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.2		Amended and Restated First Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc., Vanguard Natural Gas, LLC and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.3		Amended and Restated Second Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc. and Delaware Trust Company, as collateral agent (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K15D5 filed August 2, 2017)

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10.4		Amended and Restated Second Lien Pledge and Security Agreement, dated as of August 1, 2017, by and among certain subsidiaries and affiliates of Vanguard Natural Resources, Inc. and Delaware Trust Company, as collateral agent (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.5		Amended and Restated Intercreditor Agreement, dated as of August 1, 2017, by and among Citibank, N.A., as priority lien agent, and Delaware Trust Company, as second lien collateral trustee, and acknowledged and agreed to by Vanguard Natural Gas, LLC, Vanguard Natural Resources, Inc. and the other grantors party thereto (incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.6		Amended and Restated Collateral Trust Agreement, dated as of August 1, 2017, by and among Vanguard Natural Resources, Inc., the grantors and guarantors named therein and Delaware Trust Company as trustee and as collateral trustee (incorporated by reference to Exhibit 10.6 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.7		Registration Rights Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc. and certain parties thereto (incorporated by reference to Exhibit 10.7 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.8		Warrant Agreement, dated as of August 1, 2017, between Vanguard Natural Resources, Inc., as Issuer, and American Stock Transfer & Trust Company, LLC, as warrant agent (incorporated by reference to Exhibit 10.8 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.9*		Second Amended and Restated Employment Agreement of Scott W. Smith, dated August 1, 2017 (incorporated by reference to Exhibit 10.9 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.10*		Second Amended and Restated Employment Agreement of Britt Pence, dated August 1, 2017 (incorporated by reference to Exhibit 10.11 to our Current Report on Form 8-K15D5 filed August 2, 2017)
10.11*		Employment Agreement of Jonathan C. Curth, effective as of December 4, 2017 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 4, 2017)
10.12*		Employment Agreement with Richard Scott Sloan, dated January 17, 2018 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed January 18, 2018)
10.13*		Employment Agreement with Ryan Midgett, dated January 17, 2018 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed January 18, 2018)
10.14*		Vanguard Natural Resources, Inc. Management Incentive Plan (incorporated by reference to Exhibit 10.13 to our Quarterly Report on Form 10-Q filed November 9, 2017)
10.15**		Form of Director Deferred Restricted Stock Unit Award Agreement
10.16*		Form of Restricted Stock Unit Award Agreement (Performance Based) (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed January 18, 2018)
10.17*		Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed January 18, 2018)
21.1**		Subsidiaries of Vanguard Natural Resources, Inc.
23.1**		Consent of BDO USA, LLP, Independent Registered Public Accounting Firm
23.2**		Consent of Miller and Lents, Independent Petroleum Engineers and Geologists
24.1		Power of Attorney (included on signature page hereto)
31.1**		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
31.2**		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
32.1**		Section 1350 Certification of Chief Executive Officer
32.2**		Section 1350 Certification of Chief Financial Officer
99.1**		Report of Miller and Lents, Ltd., Independent Petroleum Engineers and Geologists
99.2		Order Confirming Debtors’ Modified Second Amended Joint Plan of Reorganization under Chapter 11 of Bankruptcy Code of Vanguard Natural Resources, LLC (incorporated by reference to Exhibit 99.1 to our Predecessor’s Current Report on Form 8-K filed July 19, 2017)
101.INS**		XBRL Instance Document
101.SCH**		XBRL Schema Document
101.CAL**		XBRL Calculation Linkbase Document
101.DEF**		XBRL Definition Linkbase Document
101.LAB**		XBRL Label Linkbase Document
101.PRE**		XBRL Presentation Linkbase Document

_______________

166

* Management Contract or Compensatory Plan or Arrangement required to be filed as an Exhibit hereto pursuant to Item 601 of Regulation S-K


**	Provided herewith.

167

ITEM 16. FORM 10-K SUMMARY

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 on the 21st day of March, 2018.



VANGUARD NATURAL RESOURCES, INC.
		/s/ R. Scott Sloan
		R. Scott Sloan
		President and Chief Executive Officer

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints R. Scott Sloan, Ryan Midgett and Jonathan Curth, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this Annual Report, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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March 21, 2018	/s/ R. Scott Sloan
	R. Scott Sloan
	President, Chief Executive Officer and Director
	(Principal Executive Officer)

March 21, 2018	/s/ Ryan Midgett
	Ryan Midgett
	Chief Financial Officer
	(Principal Financial Officer)

March 21, 2018	/s/ Patty Avila-Eady
	Patty Avila-Eady
	Chief Accounting Officer
	(Principal Accounting Officer)

March 21, 2018	/s/ Joseph Citarrella
	Joseph Citarrella
	Chairman of the Board of Directors

March 21, 2018	/s/ Randall M. Albert
	Randall M. Albert
	Director

March 21, 2018	/s/ Michael Alexander
	Michael Alexander
	Director

March 21, 2018	/s/ W. Greg Dunlevy
	W. Greg Dunlevy
	Director

March 21, 2018	/s/ Graham Morris
	Graham Morris
	Director

March 21, 2018	/s/ Joseph Hurliman Jr.
	Joseph Hurliman Jr.
	Director

169

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Grizzly Energy (GRZZP) Inactive 10-K2017 FY Annual report

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