Attached files

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EX-99.1 - EXHIBIT 99.1 - Vanguard Natural Resources, Inc.ex991mlreserveauditlette.htm
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.exhibit32-2x2017xq4x10k.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.exhibit32-1x2017xq4x10k.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.exhibit31-2x2017xq4x10k.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.exhibit31-1x2017xq4x10k.htm
EX-23.2 - EXHIBIT 23.2 - Vanguard Natural Resources, Inc.exhibit232mlconsent2017.htm
EX-23.1 - EXHIBIT 23.1 - Vanguard Natural Resources, Inc.exhibit231bdoconsent2017.htm
EX-21.1 - EXHIBIT 21.1 - Vanguard Natural Resources, Inc.exhibit21-1x2017xq4x10k.htm
EX-10.15 - EXHIBIT 10.15 - Vanguard Natural Resources, Inc.exhibit10-15formofdirector.htm



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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





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
 

1





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

2




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

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

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

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

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

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

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

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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


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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

5




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”).

6




(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

7




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.


8




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

9




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

10




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.
 

11




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.
 

12




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)
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. 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 Part II, Item 8 of this Annual Report.

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.”
 

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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.


14




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.


15




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.
 

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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

17




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.

18




 

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

19




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

20




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

21




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

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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

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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.


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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.


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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.


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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

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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.

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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.


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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.


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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.

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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.

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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.


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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

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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

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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

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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.

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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

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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.

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.

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.


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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.

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.

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

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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.


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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.


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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 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.

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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

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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

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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

46




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.
 

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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.

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

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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.


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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.

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

50




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. 



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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 followi