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Filed Pursuant to Rule 424(b)(4)
Registration No. 333-223041

 

 

PROSPECTUS

 

LOGO

 

ROSEHILL RESOURCES INC.

 

6,150,000 SHARES

 

CLASS A COMMON STOCK

 

 

 

We are offering 6,150,000 shares of our Class A Common Stock, par value $0.0001 per share (“Class A Common Stock”).

 

Our Class A Common Stock is listed on The NASDAQ Capital Market (“NASDAQ”) under the symbol “ROSE.” On September 20, 2018, the closing price of our Class A Common Stock was $8.56. As of September 20, 2018, we had 6,542,368 shares of Class A Common Stock issued and outstanding.

 

We are an “emerging growth company” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is an emerging growth company.

 

 

 

Investing in our Class A Common Stock involves risks. See “Risk Factors” beginning on page 19 of this prospectus.

 

 

 

     Price to Public      Underwriting
Discounts(1)
     Proceeds
to Us
 

Per Share

   $ 6.100      $ 0.305      $ 5.795  

Total

   $ 37,515,000      $ 1,875,750      $ 35,639,250  

 

(1)   We have also agreed to reimburse the underwriters for certain of their expenses in connection with this offering. See “Underwriting (Conflicts of Interest).”

 

We have granted the underwriters an option to purchase up to an additional 922,500 shares of Class A Common Stock from us at the public offering price, less underwriting discounts, within 30 days of the date of this prospectus.

 

The shares of Class A Common Stock are expected to be ready for delivery on or about October 2, 2018.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

Citigroup   SunTrust Robinson Humphrey   J.P. Morgan

 

Senior Co-Managers

 

Fifth Third Securities   Seaport Global Securities

 

Co-Managers

 

KLR Group, LLC   A.G.P.   B. Riley FBR
Northland Capital Markets     Tuohy Brothers

 

 

 

The date of this prospectus is September 27, 2018


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1  

RISK FACTORS

     19  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     52  

USE OF PROCEEDS

     54  

PRICE RANGE OF CLASS A COMMON STOCK AND DIVIDEND POLICY

     55  

CAPITALIZATION

     57  

SELECTED HISTORICAL FINANCIAL INFORMATION

     58  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     61  

DESCRIPTION OF BUSINESS

     94  

MANAGEMENT

     123  

EXECUTIVE AND DIRECTOR COMPENSATION

     130  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     138  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     148  

UNDERWRITING (CONFLICTS OF INTEREST)

     151  

DESCRIPTION OF CAPITAL STOCK

     157  

CERTAIN ERISA CONSIDERATIONS

     167  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

     169  

LEGAL MATTERS

     173  

EXPERTS

     173  

WHERE YOU CAN FIND MORE INFORMATION

     173  

INDEX TO FINANCIAL STATEMENTS

     F-1  

 

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus we may authorize to be delivered or made available to you relating to this offering. We have not, and the underwriters have not, authorized anyone to provide you with different or additional information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, offering to sell, or seeking offers to buy, these securities in jurisdictions where offers and sales are not permitted. You should not assume that the information contained in this prospectus or any free writing prospectus relating to this offering is accurate as of any date other than its respective date. Our business, financial condition, results of operations and prospects may have changed since that date.

 

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PROSPECTUS SUMMARY

 

This summary highlights certain information appearing elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our Class A Common Stock. For a more complete understanding of this offering, you should read the entire prospectus carefully, including the information presented under the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” and the financial statements and related notes thereto.

 

Unless the context otherwise requires, references in this prospectus to (i) “Rosehill Resources,” “the Company,” “our company,” “we,” “our” and “us,” or like terms, refer to Rosehill Resources Inc. and its subsidiaries, including Rosehill Operating Company, LLC, and (ii) “Rosehill Operating” refer to Rosehill Operating Company, LLC, an entity of which we act as the sole managing member and of whose common units we currently own approximately 18.0% (or 33.8% assuming the conversion of our Series A preferred units in Rosehill Operating into common units in Rosehill Operating (the “Rosehill Operating Common Units”)). Pro forma for the completion of this offering, we expect to own approximately 29.9% of Rosehill Operating’s Common Units (or 41.7% assuming the conversion of our Series A preferred units in Rosehill Operating into Rosehill Operating Common Units).

 

Unless the context otherwise requires, (i) prior to the completion of the Transaction (as defined below), references in this prospectus to “Rosehill Operating” refer to the assets, liabilities and operations of the business that were contributed to Rosehill Operating Company, LLC in connection with the Transaction and (ii) following the completion of the Transaction, references in this prospectus to “Rosehill Operating” refer to Rosehill Operating Company, LLC. Unless stated otherwise or the context otherwise requires, the information in this prospectus (i) assumes that the underwriters will not exercise their option to purchase additional shares of Class A Common Stock, (ii) does not include the future issuance of Class A Common Stock under the Amended and Restated Rosehill Resources Inc. Long-Term Incentive Plan (as amended, restated or otherwise modified from time to time) and (iii) does not include any shares of Class A Common Stock issuable upon conversion of our Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.0001 per share (the “Series A Preferred Stock”), upon redemption of Rosehill Operating Common Units or upon exercise of our outstanding warrants.

 

Our Company

 

We are an independent oil and natural gas company focused on the acquisition, exploration, development, and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and Southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Central Basin Platform and the Delaware Basin. Since the sale of our Barnett Shale assets during the fourth quarter of 2017 (the “Barnett Shale Asset Sale”), our assets are concentrated within the Delaware Basin, and we divide our operations into two core areas: the Northern Delaware Basin and the Southern Delaware Basin.

 

We were incorporated in Delaware on September 21, 2015 as a special purpose acquisition company under the name of KLR Energy Acquisition Corporation (“KLRE”) for the purpose of effecting a merger, asset acquisition, capital stock exchange, stock purchase, reorganization or similar business combination involving us and one or more businesses. On April 27, 2017, we acquired a portion of the equity of Rosehill Operating, an entity into which Tema Oil & Gas Company (“Tema”), a wholly owned subsidiary of Rosemore, Inc. (“Rosemore”), contributed certain assets and liabilities (the “Transaction”). At the closing of the Transaction, we became the sole managing member of Rosehill Operating and we changed our name to Rosehill Resources Inc.

 

Our sole material asset is our interest in Rosehill Operating. As the sole managing member of Rosehill Operating, we, through our officers and directors, are responsible for all operational, management and

 

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administrative decisions relating to Rosehill Operating’s business without the approval of any other member, unless otherwise specified in the Second Amended and Restated Limited Liability Company Agreement of Rosehill Operating (the “Second Amended LLC Agreement”).

 

Our management team has significant experience identifying, acquiring and developing unconventional oil and natural gas assets with the objective of being a returns-oriented pure-play Delaware Basin company focusing on (i) acreage with reduced development risk as a result of being in proved areas within the vicinity of other successful wells, (ii) stacked pay zones, including Brushy Canyon, Avalon/1st Bone Spring, 2nd Bone Spring, 3rd Bone Spring, Upper Wolfcamp A (X/Y), Lower Wolfcamp A, and Wolfcamp B, and (iii) application of geology, optimizing well process improvements and well returns. We believe these characteristics enhance our horizontal production capabilities, recoveries and economic results.

 

Since 2012, we have drilled 64 horizontal wells in the Delaware Basin with a continuing drop in drilling times and an increase in operational capabilities and efficiencies. In the second quarter of 2018, our production averaged 18,429 net barrels of oil equivalent per day, an increase of 148% as compared to the daily average of the fourth quarter of 2017. We have assembled a multi-year inventory of horizontal development and exploration projects, including projects to further evaluate the regional extent and multi-pay potential of our assets. As of June 30, 2018, our portfolio included 53 gross operated producing horizontal wells located in the Northern Delaware Basin and working interests in approximately 11,563 net acres in the Delaware Basin. As of December 31, 2017, our portfolio included an inventory of 530 gross operated and non-operated potential horizontal drilling locations.

 

We have identified 480 gross operated and 50 gross non-operated potential horizontal drilling locations, including 29 locations associated with proved undeveloped reserves as of December 31, 2017, in up to ten formations from Brushy Canyon down through the Wolfcamp B. As of December 31, 2017, 32 of our gross operated potential horizontal drilling locations in the Northern Delaware Basin were uneconomic using Securities and Exchange Commission (“SEC”) pricing assumptions. We believe that development drilling of our identified gross operated potential horizontal drilling locations, together with an increased focus on maximizing the value of existing assets by optimizing completions, reducing horizontal drilling costs, efficiently building out facilities, and reducing operating costs, will allow us to grow our production and reserves. We also intend to grow our production and reserves through acquisitions that meet certain strategic and financial objectives. As of December 31, 2017, our operated potential horizontal drilling locations are reflected in the table below:

 

     Operated
Potential Horizontal
Drilling Locations(1)(2)(3)(4)
 
     Gross      Net  

Target Formation:

     

Brushy Canyon

     33        30  

Upper Avalon

     10        10  

Lower Avalon / 1st Bone Spring

     45        41  

2nd Bone Spring Shale

     19        19  

2nd Bone Spring Sand

     61        56  

3rd Bone Spring Shale

     19        19  

3rd Bone Spring Sand

     50        44  

Upper Wolfcamp A (X/Y)

     70        63  

Lower Wolfcamp A

     80        71  

Wolfcamp B

     93        85  
  

 

 

    

 

 

 

Total Horizontal Locations(5)

     480        438  
  

 

 

    

 

 

 

 

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(1)   Our estimated drilling locations are based on well spacing assumptions and the evaluation of our horizontal drilling results as well as results of other operators in the area, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of a vertical well that penetrated all of our targeted horizontal formations. In addition, to evaluate the prospects of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis, and drill cuttings analysis and acquired and interpreted modern 3-D seismic data.
(2)   Our inventory of operated potential horizontal drilling locations assumes four to six wells per 640-acre section within each of the ten formations, with the number of prospective formations varying from tract to tract depending on the geology of the specific area.
(3)   Our identified operated potential horizontal drilling locations are located on operated and non-operated acreage. We operate approximately 91% of our 530 identified gross potential horizontal drilling locations. Of the 29 identified gross potential horizontal drilling locations associated with proved undeveloped reserves, 28 are operated and one is non-operated. As of June 30, 2018, we had an approximate 86% average working interest in our operated acreage.
(4)   Includes proved undeveloped (“PUD”) locations on our leasehold in the Northern Delaware Basin.
(5)   The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, seasonal restrictions, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified potential horizontal drilling locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. The identified gross potential horizontal drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the capital that would be necessary to drill such locations.

 

For the remainder of the year, we expect to keep one rig operating in the Northern Delaware area and one rig operating in the Southern Delaware area. We expect to drill 34 to 38 new wells and complete 34 to 38 of those wells in 2018, comprised of 24 to 26 wells drilled and 28 to 30 completed in the Northern Delaware area and 10 to 12 wells drilled and six to eight completed in the Southern Delaware area. We expect our 2018 capital budget for drilling, completion and recompletion activities and facilities costs to be in the range of $350 to $375 million, excluding acreage acquisitions. We anticipate that 80-85% of our 2018 capital costs will be incurred in connection with drilling and completion activities.

 

Recent Events

 

Credit Agreement

 

On March 28, 2018, we entered into an Amended and Restated Credit Agreement (the “Amended and Restated Credit Agreement”) by and among us, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. The Amended and Restated Credit Agreement amends and restates in its entirety the original Credit Agreement entered into on April 27, 2017 and amended on December 8, 2017. Pursuant to the Amended and Restated Credit Agreement, the lenders party thereto have agreed to provide us with a $500 million secured reserve-based revolving credit facility with an initial borrowing base of $150 million. The maturity date of the Amended and Restated Credit Agreement is August 31, 2022. The maturity date will be automatically extended to March 2023 upon the payment in full of the Second Lien Notes. The borrowing base will be redetermined semi-annually, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The first redetermination occurred on June 29, 2018, increasing the borrowing base from $150 million to $210 million.

 

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On March 28, 2018, Rosehill Operating entered into a Limited Consent and First Amendment to Note Purchase Agreement (the “First Amendment”), among Rosehill Operating, as issuer, the Company, each of the holders from time to time party thereto and U.S. Bank National Association, as agent and collateral agent for the holders, which amends certain provisions of the Note Purchase Agreement to conform to provisions in the Amended and Restated Credit Agreement.

 

White Wolf Acquisition

 

On December 8, 2017 (the “White Wolf Closing Date”), we acquired mineral rights and royalty interest to 4,565 net acres and other associated assets and interests in the Southern Delaware Basin (the “White Wolf Acquisition”) for approximately $77.6 million in cash, subject to customary purchase price adjustments, pursuant to a Purchase and Sale Agreement from certain sellers named therein (the “Sellers”).

 

On the White Wolf Closing Date, we also secured financing for the transaction from certain private funds and accounts managed by EIG Global Energy Partners, LLC (collectively, “EIG”) through the issuance and sale (i) by us of 150,000 shares of 10.000% Series B Redeemable Preferred Stock, par value $0.0001 per share (the “Series B Preferred Stock”) for an aggregate purchase price of $150.0 million and (ii) by Rosehill Operating of $100.0 million in aggregate principal amount of 10.00% Senior Secured Second Lien Notes due January 31, 2023 (the “Second Lien Notes”). We have the option, subject to certain conditions, to issue and sell from time to time up to an additional 50,000 shares of Series B Preferred Stock for a purchase price of $1,000 per share of Series B Preferred Stock. Such option terminates on December 8, 2018. For a discussion of our Series B Preferred Stock, please read “Description of Capital Stock.” For a discussion of the Second Lien Notes, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Capital Requirements and Sources of Liquidity—Debt Agreements—Second Lien Notes.”

 

The proceeds received from the issuance of the Series B Preferred Stock and the Second Lien Notes were used to fund the White Wolf Acquisition, to fully repay all amounts outstanding under our revolving credit facility, and to pay related financing costs. The remaining proceeds and any proceeds received from any future issuance of the additional 50,000 shares of Series B Preferred Stock will be used to fund capital development.

 

On December 21, 2017, we acquired from the Sellers additional mineral rights and royalty interest to 1,940 net acres and other associated assets and interest in the Southern Delaware Basin for $39.0 million.

 

Operational Update

 

In early September 2018, our net daily production exceeded 20,000 barrels of oil equivalent. This rate is expected to be sustained going forward, excluding fluctuations due to weather and downtime associated with simultaneous operations.

 

The Company recently placed several wells onto production located on its Weber lease in Loving County, Texas with the following highlights:

 

   

Weber 26 F-1 (LWCA) reached an initial production rate during a 24 hour period of 1,827 Boe/d, 81% oil, or 381 Boe/d per 1,000 ft.

 

   

Weber 26 F-2 (WCA X/Y) reached an initial production rate during a 24 hour period of 1,641 Boe/d, 82% oil, or 376 Boe/d per 1,000 ft.

 

   

Weber 26 E-1 (LWCA) reached an initial production rate during a 24 hour period of 1,467 Boe/d, 80% oil, or 336 Boe/d per 1,000 ft.

 

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Our Business Strategies

 

Our primary business objective is to increase stockholder value through the execution of the following strategies.

 

   

Maximize Returns by Optimizing Drilling and Completion Techniques and Improving Operational Efficiency.    Our experienced management and technical teams have a proven track record of optimizing drilling and completion techniques to drive well and field-level returns. We have experienced a significant decrease in our drilling time and increase in our operational capabilities and efficiencies. These trends have been driven in part by efficiency improvements in the field, including reduced drilling days, the modification of well designs and reduction or elimination of unnecessary costs, such as eliminating the use of snubbing units to install tubing into a live well, reducing the number of trips in and out of the wellbore during drilling by switching to a more engineered drill bit selection, and utilizing a third-party mud consultant to monitor the mud program and properties thereby reducing the chemical usage and improving the rate of penetration. We extensively employ pad drilling and sequential well completion, an approach we believe reduces drilling days and maximizes ultimate recovery of the reservoir by minimizing degradation in offset-well performance due to drops in pressure as resource is extracted subsurface. We have observed and integrated best practices from Delaware Basin operators on our acreage and have benefited from drilling efficiencies and enhanced completion techniques.

 

   

Grow Production, Cash Flow and Reserves by Developing Our Extensive Delaware Basin Drilling Inventory.    We intend to selectively develop our acreage base in an effort to maximize its value and resource potential. We will pursue drilling opportunities that offer competitive returns that we consider to be low risk based on production history and industry activity in the area and repeatable as a result of well-defined geological properties over a large area. Through the conversion of our resource base to developed reserves, we will seek to increase our reserves, production and cash flow while generating favorable returns on invested capital. Our proved reserves increased 135% from year-end 2016 to 31.1 MMBoe at December 31, 2017, and in the second quarter of 2018, our production averaged 18,429 net barrels of oil equivalent per day, an increase of 148% as compared to the daily average of the fourth quarter of 2017. We will continue to closely monitor operators throughout the basin, including those with active leases on adjoining properties, or offset operators, as they delineate acreage and zones, providing us further data to optimize our development plan over time. We believe this strategy will allow us to significantly grow our reserves, production and cash flow while efficiently allocating capital to maximize the value of our resource base.

 

   

Pursue Additional Leasing and Strategic Acquisitions.    We intend to focus primarily on increasing our acreage position through leasing in the immediate vicinity of our existing Delaware Basin acreage, while selectively pursuing other acquisition opportunities that meet our strategic and financial objectives. Our acreage position extends through what we believe are multiple oil and natural gas producing stratigraphic horizons in the Delaware Basin, which we refer to as the stacked pay core, and we believe we can economically and efficiently add and integrate additional acreage into our current operations. We have a proven history of acquiring leasehold positions in the Delaware Basin that have substantial oil-weighted resource potential, and believe our management team’s extensive experience operating in the Delaware Basin provides us with a competitive advantage in identifying leasing opportunities and acquisition targets and evaluating resource potential.

 

   

Maintain a High Degree of Operational Control.    We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies. As the operator of approximately 93% of our net acreage, we are able to effectively manage (i) the timing and level of our capital spending, (ii) our development drilling strategies and (iii) our operating costs. We believe this flexibility to manage our development program allows us to optimize our field-level returns and profitability.

 

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Maintain a Conservative Financial Position.    We seek to maintain a conservative financial position. We expect to fund our growth with cash on hand, including proceeds received from the issuance of the Series B Preferred Stock and the Second Lien Notes, cash flow from operations, borrowings under our revolving credit facility, additional issuances of Series B Preferred Stock to EIG and by opportunistically accessing the capital markets. We intend to continue allocating capital in a disciplined manner and proactively managing our cost structure to achieve our business objectives. Consistent with our disciplined approach to financial management, we expect to maintain an active hedging program that seeks to reduce our exposure to commodity price volatility and to protect our cash flow and capital program.

 

Our Competitive Strengths

 

We believe the following strengths will assist in the successful execution of our business strategies:

 

   

Attractively Positioned in the Oil-Rich Delaware Basin.    We have accumulated a leasehold position of approximately 11,563 net acres in the Delaware Basin as of June 30, 2018. We believe the Delaware Basin is an attractive operating area due to its immense original oil-in-place, favorable operating environment, multiple proven horizontal reservoirs, high oil and liquids-rich natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates. In addition to leveraging our technical expertise in this core area, our geographically concentrated acreage position allows us to capitalize on economies of scale with respect to drilling and production costs. Based on our drilling and production results to date and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core Delaware Basin operating area.

 

   

Leverage Extensive Industry Experience and Veteran Leadership to Optimize Operations and to Evaluate and Execute Strategic Acquisitions.    Our management and technical teams have an extensive track record of forming and building businesses in North American resource plays. Our management team has extensive engineering, geological, geophysical, technical and operational expertise in successfully developing and operating properties. As a result of our management’s operational expertise, we experienced an increase in our proved reserves of 135% from year-end 2016 to 31.1 MMBoe at December 31, 2017, and in the second quarter of 2018, our production averaged 18,429 net barrels of oil equivalent per day, an increase of 148% as compared to the daily average of the fourth quarter of 2017. Our management also has significant experience in successfully sourcing, evaluating and executing acquisition opportunities, including multiple privately sourced acquisitions that make up the majority of our current acreage position. We regularly initiate and review acquisition opportunities and intend to pursue future acquisitions that meet our strategic and financial objectives. We believe our understanding of the geology and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to grow our resource base and maximize stockholder value.

 

   

Operating Control Over the Majority of Our Asset Portfolio and High Working Interests.    Because we operate approximately 93% of our net acreage, the amount and timing of our capital expenditures are largely subject to our discretion. Our operated acreage provides us with flexibility to manage our drilling program and optimize our returns and profitability. As of June 30, 2018, our average working interest in our operated and non-operated wells in the Delaware Basin was approximately 86% and 16%, respectively. High working interests allow us to leverage our operational team more effectively and generate better returns.

 

   

Conservative Capital Structure.    As of August 31, 2018, after giving effect to this offering and the application of the net proceeds therefrom (including any proceeds from the exercise of the underwriters’ option to purchase additional shares), we would have had approximately $25.0 million of available borrowing capacity under our revolving credit facility and $52.0 million of cash on hand and access to up to $50 million through additional issuances of Series B Preferred Stock to EIG. We will continue to seek

 

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to maintain financial flexibility to allow us to actively pursue our drilling, development and exploration activities across our portfolio and maximize our ability to complete any incremental acquisition opportunities.

 

Organizational Structure

 

We are a holding company whose sole material asset is our interest in Rosehill Operating. We are the managing member of Rosehill Operating and are responsible for all operational, management and administrative decisions relating to Rosehill Operating’s business. Tema owns 29,807,692 Rosehill Operating Common Units and a like number of shares of our Class B Common Stock. Each share of Class B Common Stock has no economic rights but entitles the holder to one vote on all matters to be voted on by our shareholders generally. Holders of our Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to our shareholders for their vote or approval, except as required by applicable law or by our certificate of incorporation.

 

The Second Amended LLC Agreement provides Tema with a redemption right, which entitles Tema to cause Rosehill Operating to redeem, from time to time, all or a portion of its Rosehill Operating Common Units (together with a corresponding number of shares of Class B Common Stock) for, at Rosehill Operating’s option, newly issued shares of Class A Common Stock on a one-for-one basis or an equivalent amount of cash. Alternatively, upon exercise of the redemption right, we (instead of Rosehill Operating) have the right (the “call right”) to, for administrative convenience, acquire each tendered Rosehill Operating Common Unit directly from Tema for Class A Common Stock or cash at our election.

 

In connection with the closing of the Transaction, we entered into a Tax Receivable Agreement with Tema. This agreement generally provides for the payment by us to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that we actually realize or are deemed to realize in certain circumstances as a result of certain increases in the tax basis in the assets of Rosehill Operating and certain benefits attributable to imputed interest. We will retain the benefit of the remaining 10% of these cash savings.

 

Payments will generally be made under the Tax Receivable Agreement as we realize actual cash tax savings in periods after the Transaction from the tax benefits covered by the Tax Receivable Agreement. However, if the Tax Receivable Agreement terminates early, either at our election in connection with certain mergers or other changes of control or as a result of our breach of a material obligation thereunder, we could be required to make a substantial, immediate lump sum payment in advance of any actual cash tax savings. We will be dependent on Rosehill Operating to make distributions to us in an amount sufficient to cover our obligations under the Tax Receivable Agreement.

 

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The following diagram illustrates our ownership structure immediately following this offering (assuming that the underwriters’ option to purchase additional shares is not exercised).

 

LOGO

 

(1)   “Series B Preferred Stock Purchasers” refers to certain private funds and accounts managed by EIG Global Energy Partners, LLC.
(2)   “Company Affiliates” refers to KLR Energy Sponsor, LLC (“KLR Sponsor”), certain of our current and former directors and officers, and certain of our shareholders who own greater than 10% of the Company’s common stock.
(3)   Includes Class B Common Stock, Series A Preferred Stock and warrants held by Tema Oil and Gas Company.
(4)   The economic and voting interests set forth above do not take into account (i) the exercise of outstanding warrants for shares of Class A Common Stock, (ii) the future issuance of shares of Class A Common Stock under the Amended and Restated Rosehill Resources Inc. Long-Term Incentive Plan or (iii) the conversion of Series A Preferred Stock into shares of Class A Common Stock or the redemption of Rosehill Operating Common Units (and corresponding shares of Class B Common Stock) for shares of Class A Common Stock.
(5)   In connection with the conversion of our remaining Series A Preferred Stock into Class A Common Stock, the Rosehill Operating Series A preferred units owned by us will convert into Rosehill Operating Common Units and, on an as-converted basis, we will own approximately 41.7% of the Rosehill Operating Common Units.

 

Implication of Being an Emerging Growth Company

 

We qualify as an “emerging growth company” as defined in the JOBS Act. As an emerging growth company, we are allowed to take advantage of specified reduced disclosure and other requirements that are otherwise not applicable generally to public companies. These provisions include:

 

   

Reduced disclosure about our executive compensation arrangements;

 

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No requirement for non-binding advisory votes on executive compensation or golden parachute arrangements; and

 

   

Exemption from the auditor attestation requirement in the assessment of our internal control over financial reporting.

 

In addition, the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933 for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected not to opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard.

 

We may take advantage of these provisions for up to five years or such earlier time that we are no longer an emerging growth company. We would cease to be an emerging growth company on the date that is the earliest of (i) the last day of the fiscal year in which we have total annual gross revenues of $1.07 billion or more (as adjusted for inflation pursuant to SEC rules from time to time); (ii) the last day of our fiscal year following the fifth anniversary of the date of the completion of our initial public offering; (iii) the date on which we have issued more than $1.0 billion in non-convertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under rules of the SEC. We have taken advantage of reduced reporting requirements in this prospectus. Accordingly, the information contained herein may be different than the information you might receive from other public companies in which you have a beneficial ownership.

 

Principal Executive Offices and Internet Address

 

Our principal executive offices are located at 16200 Park Row, Suite 300, Houston, Texas 77084, and our telephone number at that address is (281) 675-3400.

 

Our website address is www.rosehillresources.com.  We make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

 

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The Offering

 

Issuer

Rosehill Resources Inc.

 

Class A Common Stock offered by us

6,150,000 shares (or 7,072,500 shares if the underwriters exercise their option to purchase additional shares).

 

Class A Common Stock outstanding after this offering(1)

12,692,368 shares (or 13,614,868 shares if the underwriters exercise their option to purchase additional shares).

 

Other equity securities outstanding after this offering(1)

   

29,807,692 shares of Class B Common Stock

 

   

99,647 shares of 8.0% Series A Cumulative Perpetual Preferred Stock

 

   

153,630 shares of 10.0% Series B Redeemable Preferred Stock

 

   

25,594,158 warrants exercisable into shares of Class A Common Stock

 

  For a discussion of our Class B Common Stock, Series A Preferred Stock, Series B Preferred Stock and warrants, please read “Description of Capital Stock.”

 

Use of proceeds

We expect to receive approximately $34.8 million of net proceeds from this offering, after deducting underwriting discounts and estimated offering expenses payable by us. We anticipate that we will contribute all of the net proceeds from this offering to Rosehill Operating in exchange for a number of Rosehill Operating Common Units equal to the number of shares of Class A Common Stock issued by us in this offering.

 

  Rosehill Operating intends to use the net proceeds from this offering to finance its development plan and for general corporate purposes, including to fund potential future acquisitions. Please read “Use of Proceeds.”

 

Dividend policy

We do not anticipate paying any cash dividends on our Class A Common Stock. Please read “Dividend Policy.”

 

Redemption right of Tema

Under the Second Amended LLC Agreement, Tema has the right to cause Rosehill Operating to redeem, from time to time, all or a portion of its Rosehill Operating Common Units (together with a corresponding number of shares of Class B Common Stock) for, at Rosehill Operating’s option, (i) newly issued shares of Class A Common Stock on a one-for-one basis or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the redemption right, we (instead of Rosehill Operating) have the right (the “call right”) to acquire each tendered Rosehill Operating Common Unit directly from Tema for Class A Common Stock or cash at our election. In

 

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connection with any redemption of Rosehill Operating Common Units pursuant to the redemption right or call right, the corresponding number of shares of Class B Common Stock will be cancelled. See “Certain Relationships and Related Party Transactions—Agreements Relating to the Transaction—Amended and Restated Limited Liability Company Agreement of Rosehill Operating.”

 

Tax Receivable Agreement

In connection with the closing of the Transaction, we entered into a Tax Receivable Agreement with Tema which generally provides for the payment by us to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax that we actually realize or are deemed to realize in certain circumstances in periods after the closing of the Transaction as a result of certain tax basis increases and certain tax benefits attributable to imputed interest. We will retain the benefit of the remaining 10% of these cash savings. See “Risk Factors—Risks Related to the Class A Common Stock and Our Capital Structure” and “Certain Relationships and Related Party Transactions—Agreements Relating to the Transaction—Tax Receivable Agreement.”

 

Conflicts of Interest

Affiliates of KLR Investments beneficially own in excess of 10% of our issued and outstanding Class A Common Stock. Because KLR Group, LLC is an underwriter in this offering and its affiliates own in excess of 10% of our issued and outstanding Class A Common Stock, KLR Group, LLC is deemed to have a “conflict of interest” under Rule 5121 (“Rule 5121”) of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering is being made in compliance with the requirements of Rule 5121. Pursuant to that rule, the appointment of a “qualified independent underwriter” is not required in connection with this offering as the member primarily responsible for managing the public offering does not have a conflict of interest, is not an affiliate of any member that has a conflict of interest and meets the requirements of paragraph (f)(12)(E) of Rule 5121. See “Underwriting (Conflicts of Interest).”

 

Listing and trading symbol

Our Class A Common Stock is quoted on the NASDAQ Capital Market under the symbol “ROSE.”

 

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A Common Stock.

 

(1)   The number of shares of Class A Common Stock does not include (i) the 5,535,803 shares of Class A Common Stock available for future issuance under the Amended and Restated Rosehill Resources Inc. Long-Term Incentive Plan or (ii) any shares of Class A Common Stock issuable upon conversion of Series A Preferred Stock, upon a redemption of Rosehill Operating Common Units (together with a corresponding number of shares of Class B Common Stock), or upon exercise of our outstanding warrants. The outstanding number of shares of Class A Common Stock and warrants exercisable into shares of Class A Common Stock include 29,297 outstanding units, each consisting of one share of Class A Common Stock and one warrant.

 

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Summary Historical Financial Information

 

We have no direct operations and no significant assets other than our ownership interest in Rosehill Operating, an entity of which we act as the sole managing member and of whose Rosehill Operating Common Units we currently own approximately 18.0% (or 33.8% assuming the conversion of our Rosehill Operating Series A preferred units into Rosehill Operating Common Units). Pro forma for the completion of this offering, we expect to own approximately 29.9% of Rosehill Operating Common Units (or 41.7% assuming the conversion of our Series A preferred units in Rosehill Operating into Rosehill Operating Common Units). Rosehill Operating is considered our accounting predecessor. Unless the context otherwise requires, (i) prior to the completion of the Transaction, references to “Rosehill Operating” refer to the assets, liabilities and operations of the business that were contributed to Rosehill Operating Company, LLC in connection with the Transaction and (ii) following the completion of the Transaction, references to “Rosehill Operating” refer to Rosehill Operating Company, LLC.

 

The following table shows our summary historical financial information, and certain pro forma financial information, for the periods indicated. Our summary historical financial information as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015 was derived from our audited historical consolidated financial statements included elsewhere in this prospectus. Our summary historical financial information as of December 31, 2015 was derived from our audited historical financial statements not included in this prospectus. Our summary unaudited interim historical financial information as of June 30, 2018 and for the six months ended June 30, 2018 and 2017 was derived from our unaudited interim historical condensed financial statements included elsewhere in this prospectus. The summary unaudited interim historical financial information has been prepared on a consistent basis with the audited financial statements. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of acquisitions, fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors. In addition, because the historical information for the years ended December 31, 2016 and 2015 relates to periods prior to the completion of the Transaction and reflects 100% of Rosehill Operating’s financial results, such historical information may not be indicative of our results following the Transaction due in part to our 18.0% ownership interest in Rosehill Operating.

 

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The summary historical financial information should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the financial statements and accompanying notes included elsewhere in this prospectus.

 

     Six Months Ended
June 30
    Year Ended December 31,  
     2018     2017     2017     2016     2015  
     (unaudited)                    
     (in thousands, except per share data)  

STATEMENTS OF OPERATIONS DATA

          

Total revenues

   $ 136,313     $ 32,166     $ 76,236     $ 34,645     $ 29,487  

Operating income (loss)

     32,854       1,002       8,894       (8,803     (15,207

Net income (loss)

     908       3,000       (11,948     (15,189     (14,820

Series A Preferred Stock dividends and deemed dividends

     3,897       8,072       12,936       —         —    

Series B Preferred Stock dividends, deemed dividends and return

     11,576       —         2,447       —         —    

Net income (loss) attributable to Rosehill Resources Inc. common stockholders

     7,858       (2,743     (8,520     (15,189     (14,820

Earnings (loss) per common share:

          

Basic

   $ 1.24     $ (0.47   $ (1.43   $ (2.59   $ (2.53

Diluted

     (0.70     (0.47     (1.43     (2.59     (2.53

Weighted average common shares outstanding

          

Basic

     6,327       5,857       5,945       5,857       5,857  

Diluted

     36,135       5,857       5,945       5,857       5,857  

Pro Forma Per Share Data (in thousands, except per share data)(1)

          

Pro forma net income (loss) attributable to Rosehill Resources Inc. common stockholders

          

Basic

   $ 7,858     $ (1,423   $ (8,068   $ (12,355  

Diluted:

   $ (25,264   $ (1,423   $ (8,068   $ (12,355  

Pro forma earnings (loss) per share

          

Basic

   $ 1.24     $ (0.24   $ (1.36   $ (2.11  

Diluted

   $ (0.70   $ (0.24   $ (1.36   $ (2.11  

Pro forma weighted average common shares outstanding

          

Basic

     6,327       5,857       5,945       5,857    

Diluted

     36,135       5,857       5,945       5,857    

CASH FLOW DATA

          

Net cash provided by (used in):

          

Operating activities

   $ 74,595     $ 16,883     $ 37,759     $ 11,461     $ 18,244  

Investing activities

     (224,639     (45,326     (265,497     (22,164     (16,993

Financing activities

     138,217       31,067       243,986       (8,597     17,519  

OTHER FINANCIAL DATA

          

Adjusted EBITDAX (unaudited)(2)

   $ 84,069     $ 21,699     $ 46,766     $ 18,949     $ 21,743  

 

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     June 30,
2018
     December 31,  
     2017      2016      2015  
     (unaudited)                       

BALANCE SHEET DATA

           

Total current assets

   $ 49,391      $ 43,543      $ 16,343      $ 33,696  

Property and equipment, net

     585,080        432,615        123,373        122,873  

Total assets

     654,291        476,982        139,826        156,903  

Total current liabilities

     114,945        103,400        14,223        29,165  

Long-term debt, net

     238,735        93,199        55,000        45,000  

Mezzanine equity—Series B Preferred Stock

     147,941        140,868        —        —  

Total stockholders’ equity / parent net investment

     113,075        122,664        65,220        78,977  

 

(1)   The pro forma data is provided for illustrative purposes only. We incurred non-recurring transaction costs that were directly attributable to the Transaction of $2.5 million for the six months ended June 30, 2017, and $2.6 million and $2.8 million for the years ended December 31, 2017 and 2016, respectively. Pro forma per share data was recalculated excluding transaction costs. For the six months ended June 30, 2017 and the year ended December 31, 2017, the portion of transaction costs related to our 16% and 17% ownership, respectively, was reduced from the net loss attributable to our common stockholders. We do not expect to incur such transaction expense from our normal operations going forward.
(2)   Adjusted EBITDAX is a non-GAAP financial measure.

 

Non-GAAP Financial Measure

 

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, net, income taxes, DD&A, accretion, impairment of oil and natural gas properties, exploration costs, stock-based compensation, (gains) losses on commodity derivatives excluding net cash receipts (payments) on settled commodity derivatives, one-time costs incurred in connection with the Transaction, gains and losses from the sale of assets, (gains) losses on asset retirement obligation settlements, and other non-cash operating items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles (“U.S. GAAP”).

 

Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare our results of operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with U.S. GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that its results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

 

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The following table presents an unaudited reconciliation of net loss, the most directly comparable financial measure calculated and presented in accordance with U.S. GAAP, to Adjusted EBITDAX.

 

    Six Months Ended
June 30,
    Three
Months Ended

June 30,
    Year Ended December 31,  
    2018     2017     2018     2017     2017     2016     2015  

Net income (loss) reconciliation to Adjusted EBITDAX (in thousands):

             

Net income (loss)

  $ 908     $ 3,000     $ 8,664     $ (1,414   $ (11,948   $ (15,189   $ (14,820

Interest expense, net

    8,529       974       4,662       431       2,532       1,822       3,247  

Income tax expense (benefit)

    (17,400     273       (15,210     187       1,690       148       108  

Depreciation, depletion, amortization and accretion

    57,315       17,767       36,506       9,536       36,091       24,965       23,364  

Impairment of oil and natural gas properties

    —       —       —       —       1,061       —       8,131  

(Gain) loss on unsettled commodity derivatives, net

    29,045       (3,512     10,803       (1,319     16,553       3,345       735  

Transaction costs

    —       2,469     —       1,375       2,618       2,834       —  

Stock-based compensation

    3,222       —       1,760       —       1,245       —       —  

Exploration costs

    2,311       774       1,875       457       1,747       794       960  

(Gain) loss on disposition of property and equipment

    296       (11     163       —         (4,995     (50     18  

Other (income) expense, net

    (157     (35 )     (57     (150 )     172       280       —  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX (unaudited)

  $ 84,069     $ 21,699     $ 49,166     $ 9,103     $ 46,766     $ 18,949     $ 21,743  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Summary Historical Reserve and Operating Data

 

The following tables present, for the periods and as of the dates indicated, summary data with respect to the estimated net proved oil and natural gas reserves and operating data for Rosehill Operating, an entity of which we act as sole managing member and of whose Rosehill Operating Common Units we currently own approximately 18.0% (or 33.8% assuming the conversion of our Rosehill Operating Series A preferred units into Rosehill Operating Common Units). Pro forma for the completion of this offering, we expect to own approximately 29.9% of Rosehill Operating Common Units (or 41.7% assuming the conversion of our Series A preferred units in Rosehill Operating into Rosehill Operating Common Units).

 

The reserve estimates attributable to the properties of Rosehill Operating as of December 31, 2017 and 2016 presented in the table are based on reserve reports prepared by Ryder Scott Company, L.P., our independent petroleum engineer (“Ryder Scott”). Proved reserve estimates as of December 31, 2015 were prepared internally by management. Copies of the reserve reports prepared by Ryder Scott are attached as exhibits to the registration statement of which this prospectus forms a part. All of these reserve estimates were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain summary unaudited information regarding production and sales of oil, natural gas and natural gas liquids (“NGLs”) with respect to such properties.

 

See the sections entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Description of Business—Oil and Natural Gas Data” in evaluating the material presented below.

 

     December 31,  
     2017(1)      2016(2)      2015(3)  

Proved reserves:

        

Oil (MBbls)

     18,436        7,356        5,652  

Natural gas (MMcf)

     39,316        17,355        13,899  

NGL (MBbls)

     6,142        2,985        1,994  
  

 

 

    

 

 

    

 

 

 

Total (MBoe)

     31,131        13,234        9,963  
  

 

 

    

 

 

    

 

 

 

Proved developed reserves:

        

Oil (MBbls)

     8,814        3,068        2,698  

Natural gas (MMcf)

     14,171        10,574        10,116  

NGL (MBbls)

     2,285        1,802        1,481  
  

 

 

    

 

 

    

 

 

 

Total (MBoe)

     13,461        6,633        5,865  
  

 

 

    

 

 

    

 

 

 

Proved undeveloped reserves:

        

Oil (MBbls)

     9,622        4,288        2,954  

Natural gas (MMcf)

     25,145        6,781        3,783  

NGL (MBbls)

     3,857        1,183        513  
  

 

 

    

 

 

    

 

 

 

Total (MBoe)

     17,670        6,601        4,098  
  

 

 

    

 

 

    

 

 

 

Oil and Natural Gas Prices:

        

Oil—WTI posted price per Bbl

   $ 51.34      $ 42.75      $ 50.28  

Natural gas—Henry Hub spot price per MMBtu

   $ 2.98      $ 2.49      $ 2.58  

NGL—per Bbl

   $ 31.82      $ 11.73      $ 13.83  

 

(1)  

Estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil, the average West Texas Intermediate posted price of $51.34 per barrel as of December 31, 2017 was adjusted for quality, transportation fees, and a regional price

 

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differential. For natural gas volumes, the average Henry Hub spot price of $2.98 per MMBtu as of December 31, 2017 was adjusted for energy content and a regional price differential. For December 31, 2017, NGLs were priced at $31.82 per barrel using Mont Belvieu pricing, as adjusted, and not as a percentage of West Texas Intermediate. All prices are held constant throughout the producing life of the properties.

(2)   Estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil, the average West Texas Intermediate posted price of $42.75 per barrel as of December 31, 2016 was adjusted for quality, transportation fees, and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.49 per MMBtu as of December 31, 2016 was adjusted for energy content and a regional price differential. For NGL volumes, 27.5% of the average West Texas Intermediate posted price of $42.75 per barrel, or $11.73, as of December 31, 2016 was adjusted for quality, transportation fees and a regional price differential. All prices are held constant throughout the producing life of the properties.
(3)   Estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil, the average West Texas Intermediate posted price of $50.28 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.58 per MMBtu as of December 31, 2015 was adjusted for energy content and a regional price differential. For NGL volumes, 27.5% of the average West Texas Intermediate posted price of $50.28 per barrel, or $13.83, as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. All prices are held constant throughout the producing life of the properties.

 

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     Six Months Ended
June 30,
    Year Ended December 31,  
     2018      2017     2017     2016     2015  

Production data:

           

Oil (MBbls)

     2,063        536       1,271       612       472  

Natural gas (MMcf)

     2,127        1,357       2,709       2,381       2,074  

Natural gas liquids (MBbls)

     363        205       408       358       312  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total production (MBOE)

     2,781        967       2,131       1,367       1,130  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Average daily production (BOE/d)

     15,365        5,343       5,838       3,734       3,096  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Average realized prices before effect of derivatives(1):

           

Oil (per Bbl)

   $ 60.40      $ 46.70     $ 48.46     $ 40.52     $ 43.62  

Natural gas (per Mcf)

     1.91        2.73       2.65       2.23       2.37  

Natural gas liquids (per Bbl)

     21.06        16.71       18.31       12.68       12.75  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Average price (per BOE)

   $ 49.02      $ 33.26     $ 35.77     $ 25.35     $ 26.09  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Average price after the effect of settled derivatives

(per BOE)(1)

   $ 44.63      $ 32.94     $ 35.85     $ 22.30     $ 29.40  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Average costs (per BOE)

           

Lease operating expense

   $ 7.23      $ 3.66     $ 5.11     $ 3.51     $ 4.06  

Production taxes

     2.33        1.52       1.66       1.13       1.16  

Gathering and transportation

     0.69        1.54       1.40       1.75       1.85  

Depreciation, depletion and amortization

     20.61        18.37       16.94       18.27       20.68  

Impairment of oil and natural gas properties

     0.83        0.80       0.50       —       7.20  

Exploration costs

     4.22        3.79       0.82       0.58       0.85  

General and administrative expense

     1.18        —       6.30       4.51       3.75  

Transaction expenses

     —        2.55       1.23       2.07       —  

(Gain) loss on sale of property and equipment

     0.11        (0.01     (2.34     (0.04     0.02  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total(2)

   $ 37.20      $ 32.22     $ 31.62     $ 31.78     $ 39.57  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)   Average prices shown in the table reflect prices both before and after the effects of commodity hedging settlements. Our calculation of such effects includes both gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.
(2)   May not sum or recalculate due to rounding.

 

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RISK FACTORS

 

An investment in the Class A Common Stock involves a high degree of risk. In addition to the other information included in this prospectus, you should carefully consider each of the risk factors set forth in any applicable prospectus supplement. Any of these risks and uncertainties could have a material adverse effect on our business, financial condition, cash flows and results of operations. If that occurs, the trading price of the Class A Common Stock could decline materially and you could lose all or part of your investment.

 

The risks included in this prospectus are not the only risks we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our securities.

 

Risks Related to Our Operations

 

Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

Our revenues, profitability, cash flows and future growth, as well as liquidity and ability to access additional sources of capital, depends substantially on prevailing prices for oil, natural gas, and NGLs. A reduction in or sustained lower prices will reduce the amount of oil, natural gas, and NGLs that we can economically produce and may result in impairments of our proved reserves or reduction of our proved undeveloped reserves. Oil, natural gas, and NGL prices also affect the amount of cash flow available for capital expenditures and ability to borrow and raise additional capital.

 

The markets for oil, natural gas, and NGLs have historically been volatile. For example, since 2014, the WTI spot price for oil declined from a high of $107.95 per barrel in June 2014 to a low of $26.19 per barrel in February 2016 and was $69.84 per barrel on August 31, 2018 and the NYMEX Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 per MMBtu in March 2016 and was $2.98 per MMBtu on August 31, 2018. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The price of propane (Mont Belvieu) ranged from a high of $1.70 per gallon in January 2014 to a low of $0.30 per gallon in January 2016 and was $1.04 per gallon on August 31, 2018, and the price of ethane (Mont Belvieu) ranged from a high of $0.45 per gallon in January 2014 to a low of $0.14 per gallon in December 2016 and was $0.41 per gallon on August 31, 2018.

 

The market prices for oil, natural gas, and NGLs depend on factors beyond our control. Some, but not all, of the factors that can cause fluctuation include:

 

   

worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;

 

   

the price and quantity of foreign imports of oil, natural gas, and NGLs;

 

   

political and economic conditions in, or affecting, other producing regions or countries, including the Middle East, Africa, South America, and Russia;

 

   

actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies, including the ability of members of OPEC to agree to and maintain price and production controls;

 

   

the level of global exploration, development and production;

 

   

the level of global inventories;

 

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the extent to which U.S. shale producers become “swing producers” adding or subtracting to the world supply;

 

   

prevailing prices on local price indexes in the area in which we operate;

 

   

the proximity, capacity, cost and availability of gathering and transportation facilities;

 

   

localized and global supply and demand fundamentals and transportation availability;

 

   

the cost of exploring for, developing, producing and transporting reserves;

 

   

weather conditions, other natural disasters, and climate change;

 

   

technological advances affecting energy consumption;

 

   

the price and availability of alternative fuels;

 

   

worldwide conservation measures;

 

   

domestic and foreign governmental relations, regulation, and taxes;

 

   

worldwide governmental regulation and taxes;

 

   

U.S. and foreign trade restrictions, regulations, tariffs, agreements, and treaties;

 

   

the level and effect of trading in commodity futures markets, including commodity price speculators and others; and

 

   

political conditions or hostilities and unrest in oil producing regions.

 

Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically and may impact our ability to satisfy our obligations under firm-commitment transportation agreements. We have historically been able to hedge our natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited.

 

Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

 

Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.

 

The oil and natural gas industry is capital-intensive. We make substantial capital expenditures related to development and acquisition projects. We expect to fund our capital expenditures with cash generated by operations, borrowings under the Amended and Restated Credit Agreement and through additional issuances of

 

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Series B Preferred Stock to EIG; however, financing needs may require an alteration or increase in our capitalization substantially through the issuance of debt or equity or the sale of assets. The issuance of additional debt securities would require that a portion of the cash flow from our operations be used for the payment of interest and principal, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things: oil, natural gas and NGL prices; actual drilling results; the availability and cost of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

 

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

   

the prices at which our production is sold;

 

   

our proved reserves;

 

   

the volume of hydrocarbons we are able to produce from existing wells;

 

   

our ability to acquire, locate and produce new reserves;

 

   

the levels of our operating expenses;

 

   

our ability to borrow under our Amended and Restated Credit Agreement (or any replacement credit facility); and

 

   

our ability to access the capital markets.

 

If cash flow from operations or available borrowings under our Amended and Restated Credit Agreement decrease as a result of lower oil, natural gas and NGL prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on acceptable terms, if at all. If cash flow from operations or available under existing or anticipated credit facilities are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations.

 

Drilling for oil and natural gas involves numerous and significant risks and uncertainties.

 

Risks that we face while drilling wells include:

 

   

effects of weather, floods, snowstorms, ice storms, and similar natural conditions, on the drilling location and delivery of materials to the wellsite;

 

   

unforeseen water flows;

 

   

lost circulation of drilling fluids;

 

   

unexpected oil and gas flows into the wellbore;

 

   

drill pipe, casing and equipment failure, or loss of equipment in the well;

 

   

failure or inaccuracies of directional drilling measurement devices;

 

   

excessive hole washouts in the salt/anhydrite zones resulting in poor surface cement jobs;

 

   

inability to reach the desired drilling zone with conventional bits and drilling techniques;

 

   

failure to land a wellbore in the desired drilling zone;

 

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inability to stay in the desired drilling zone or being able to run tools and other equipment consistently while drilling horizontally through the formation;

 

   

difficulties in running casing the entire length of the wellbore.

 

Risks that we face while completing wells include:

 

   

the ability to fracture stimulate the planned number of stages;

 

   

the ability to run tools the entire length of the wellbore during completion operations; and

 

   

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

 

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut-in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and a decline in the value of our undeveloped acreage.

 

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

 

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

 

Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.

 

Many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

   

delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, emissions of greenhouse gases (“GHGs”) and limitations on hydraulic fracturing;

 

   

pressure or irregularities in geological formations;

 

   

shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

   

equipment failures, accidents or other unexpected operational events;

 

   

lack of available gathering facilities or delays in construction of gathering facilities;

 

   

lack of available capacity on interconnecting transmission pipelines;

 

   

adverse weather conditions, including such conditions which are possibly connected to climate change;

 

   

drought conditions limiting the availability of water for hydraulic fracturing, including such conditions as possibly connected to climate change;

 

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issues related to compliance with environmental regulations, including protections for threatened or endangered species;

 

   

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

 

   

declines in oil and natural gas prices;

 

   

limited availability of financing at acceptable terms;

 

   

title problems; and

 

   

limitations in the market for oil and natural gas.

 

Our derivative activities could result in financial losses or could reduce our earnings.

 

A portion of our oil and natural gas production has historically been hedged in order to protect cash flow from falling prices. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. As of June 30, 2018, we had open commodity derivative contracts for the months of July 2018 through December 2022 covering a total of 10,101 MBbls of oil and 8,040 MMcf of natural gas. Additionally, we had crude oil basis swaps covering a total of 10,044 MBbls of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our commodity derivative.

 

Commodity derivatives may also expose us to the risk of financial loss in some circumstances, including when:

 

   

production and sales are insufficient to offset losses under the commodity derivatives;

 

   

the counterparty to the commodity derivatives defaults on its contractual obligations;

 

   

there is an increase in the differential between the underlying price in the commodity derivatives and actual prices received;

 

   

issues arise with regard to legal enforceability of such instruments; or

 

   

applicable laws or regulations regarding such instruments are changed.

 

The use of commodity derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into commodity derivatives that require cash collateral, particularly if commodity prices or interest rates change in a manner averse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with counterparties, highly volatile oil and natural gas prices and interest rates. In addition, commodity derivatives could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

 

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

 

During periods of declining commodity prices, our commodity derivative contract receivable positions have generally increased, which has increased our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

 

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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.

 

You should not assume that the present value of future net revenues from our estimated reserves is the current market value of such reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2017 were, and related standardized measure was, calculated under SEC rules using twelve-month unweighted average first-day-of-the-month prices of $51.34 per barrel of oil (WTI), $31.82 per barrel of NGL (Mont Belvieu), and $2.98 per MMBtu of natural gas (Henry Hub) which, for certain periods in 2017, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

 

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of our drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

 

We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the potential drilling locations our management has identified will ever be drilled or if we will be able to produce oil or natural gas in commercial qualities from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

 

As of December 31, 2017, 480 gross operated potential horizontal drilling locations have been identified on our acreage based on four to six wells per 640-acre section within each of ten formations from the Brushy Canyon through Wolfcamp B formations. As of December 31, 2017, 189 of our Northern Delaware Basin gross operated potential horizontal drilling locations, of which 29 were PUDs, were economic using SEC pricing

 

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assumptions. Horizontal lateral effective lengths across our acreage range from 4,000 feet up to 10,000 feet. As a result of the limitations described above, we may be unable to drill many of the identified locations. Further, in connection with the White Wolf Acquisition, we acquired approximately 6,505 net acres in northwestern Pecos County, Texas, which is largely unproven and relatively undrilled compared to other areas in the Delaware Basin. We have no experience drilling in Pecos County. Based on future operations or regulatory changes, we may determine that certain formations cannot be physically or economically exploited or that spacing of wells may have to be changed.

 

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “—Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.

 

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.

 

As of June 30, 2018, approximately 46.2% of our total net acreage was either held by production or under continuous drilling provisions. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

 

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

 

Water is an essential component of deep shale oil and natural gas drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas in past years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

 

All of our producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas and New Mexico, making us vulnerable to risks associated with operating in a single geographic area.

 

All of our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At December 31, 2017, 100% of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought-related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

 

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In addition to the geographic concentration of our producing properties in the Northern Delaware Basin described above, at December 31, 2017, approximately 71% percent of our proved reserves were attributable to the 3rd Bone Spring, Wolfcamp A (X/Y) and Lower Wolfcamp A formations. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field. There were no proved reserves attributable to the Southern Delaware Basin as of December 31, 2017.

 

We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

 

We have leased or acquired approximately 11,563 net acres in the Delaware Basin, approximately 93% of which we operate, as of June 30, 2018. As of December 31, 2017, we were the operator on 480 of our 530 identified gross horizontal drilling locations. We expect to operate approximately 91% of, and have an approximate 83% working interest in, the acreage we acquired and expect to operate in the White Wolf Acquisition and believe that the acreage may be prospective for six different shale formations. We will have limited ability to exercise influence over the operations of the drilling locations we do not operate, and the operators of those locations may at any time have economic, business or legal interests or goals that are inconsistent with us. Furthermore, the success and timing of development activities by such operators will depend on a number of factors that will be largely outside of our control, including:

 

   

the timing and amount of capital expenditures;

 

   

the operator’s expertise and financial resources;

 

   

the approval of other participants in drilling wells;

 

   

the selection of technology; and

 

   

the rate of production of reserves, if any.

 

This limited ability to exercise control over the operations and associated costs of some of our non-operated drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

 

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

 

We own less than 100% of the working interest on a minority of the oil and gas leases on which we conduct operations, and other unrelated parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could potentially be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Other working interest owners may be unable or unwilling to pay their share of project costs, and, in some cases, may declare bankruptcy. In the event any other working interest owners do not pay their share of such costs, we would likely have to pay those costs, and may be unsuccessful in any efforts to recover these costs from other working interest owners, which could materially adversely affect our financial position.

 

The marketability of our production will be dependent upon transportation and other facilities, certain of which we will not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

 

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is purchased at the wellhead by

 

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Gateway Gathering and Marketing (“Gateway”), an affiliate of Tema, and transported through Gateway’s Raven Gathering System (“Raven”) pipeline to the interconnection between Raven pipeline and Plains Marketing, LP pipeline. The oil is then transported on a third-party pipeline to Midland, Texas where it is sold. Our natural gas production is transported by Gateway on Gateway’s Loving County Gathering System (“LCGS”) pipeline from the wellhead to the interconnection between LCGS pipeline and ETC Field Services pipeline. The gas is sold by us to the third party (ETC Field Services) at the interconnection between LCGS and ETC Field Services. ETC Field Services transports the gas to our processing facility. In connection with the Transaction, we and Gateway entered into crude oil gathering and natural gas gathering agreements with ten-year terms.

 

We do not control Gateway’s or the third party’s transportation facilities and our access to the facilities may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut-in or curtail production or flare natural gas. Any such shut-in, curtailment, or flaring or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

 

Multi-well pad drilling may result in volatility in our operating results.

 

We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.

 

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 have historically obtained 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 minerals under the property and may be required to pay damages to the actual owner of the lease.

 

Concerns over economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

 

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

 

The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than currently anticipated. therefore, our estimated PUDs may not be ultimately developed or produced.

 

As of December 31, 2017, 57% of our total estimated proved reserves were classified as PUDs. Development of these PUDS may take longer and require higher levels of capital expenditures than currently

 

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anticipated. For example, primarily as a result of factors outside our control, including a downturn in commodity prices during 2014, we adjusted our development plan to temporarily defer the drilling of certain PUD locations. As a result, no PUDs were converted from undeveloped to developed during 2015 and 2016. As a result of our failure to convert any PUDs during 2015 and 2016, we will have a shorter period of time available to convert such PUDs (due to the requirement to convert PUDs from undeveloped to developed within five years of initial booking). Further delays in the development of our PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves if we no longer believe with reasonable certainty that we will develop the PUDs within five years after their initial booking. If we do not drill our PUD wells within five years after their respective dates of booking, we may be required to write-down our PUDs.

 

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take impairments or write-downs of the carrying values of our properties.

 

Accounting rules require periodic review of the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Commodity prices have declined significantly in recent years. For example, the WTI spot price for oil declined from a high of $107.95 per barrel in June 2014 to a low of $26.19 per barrel in February 2016, and the NYMEX Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 per MMBtu in March 2016. Likewise, NGLs have suffered significant recent declines in realized prices. The price of propane (Mont Belvieu) ranged from a high of $1.73 per gallon in February 2014 to a low of $0.30 per gallon in January 2016 and the price of ethane (Mont Belvieu) ranged from a high of $0.45 per gallon in January 2014 to a low of $0.13 per gallon in December 2015. Impairment expense for the years ended December 31, 2017, 2016, and 2015 was $1.1 million, zero, and $8.1 million, respectively. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

 

Unless we replace our reserves with new reserves and develops those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

 

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace the current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

 

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 may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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We depend upon significant purchasers for the sale of most of our oil, natural gas and NGL production.

 

We have historically sold our production to a relatively small number of customers, as is customary in our business. For the six months ended June 30, 2018 and the year ended December 31, 2017, one customer and two customers accounted for approximately 91% and 90%, respectively, of our total revenue. During such periods, no other purchaser accounted for 10% or more of our revenue. The loss of any one or all of our significant customers as a purchaser could materially and adversely affect our revenues in the short term.

 

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

 

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, occupational health and safety aspects of our operations, or otherwise relating to the protection of the environment and natural resources. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of the types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; or the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions may require us to perform difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations; and plugging and abandonment responsibilities for wells which have ceased producing. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

 

Certain environmental laws impose strict as well as joint and several liabilities for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been released into the environment. We may be required to remediate contaminated properties currently or formerly operated by us or our predecessors in interest or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. The trend has been for more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry, resulting in increased costs of doing business and consequently affecting profitability. For example, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendations for designating non-attainment areas. The EPA issued final non-attainment area designations in April 2018 and July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and

 

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costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

 

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or the insurance may be inadequate to protect us against, these risks.

 

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

 

Our exploration and development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

   

environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and air contamination;

 

   

abnormally pressured formations;

 

   

mechanical difficulties, such as stuck oilfield drilling and service tools and drill pipe or casing failures or collapse;

 

   

fire, explosions and ruptures of pipelines;

 

   

personal injuries and death;

 

   

natural disasters, which may include severe weather as possibly connected to climate change and seismic events as possibly connected to injection of produced water and flowback into disposal wells; and

 

   

terrorist attacks targeting oil and natural gas related facilities and infrastructure.

 

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

   

injury or loss of life;

 

   

damage to and destruction of property, natural resources and equipment;

 

   

pollution and other environmental damage;

 

   

statutory or regulatory investigations and penalties; and

 

   

repair and remediation costs.

 

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, statutory and regulatory penalties, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

 

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

 

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields and data from other wells in the same area, or more fully explored prospects, will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, in commercial quantities. Further, drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

   

unexpected or adverse drilling conditions;

 

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title problems;

 

   

elevated pressure or lost circulation in formations;

 

   

equipment failures or accidents;

 

   

adverse weather conditions;

 

   

compliance with environmental and other governmental or contractual requirements; and

 

   

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

 

We may be unable to make attractive acquisitions or successfully integrate acquired assets or businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

 

In the future, we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

 

The success of any completed acquisition will depend on our ability to integrate effectively the acquired assets or business. The process of integrating acquired assets or businesses may involve unforeseen difficulties and may require a disproportionate amount of managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations, which may cause the market price of our Class A common stock to decline.

 

In addition, our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement impose, and future debt agreements may impose, among other things, limitations on our ability to enter into mergers or combination transactions. See “—Risks Related to Our Indebtedness—Restrictions in our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement limit, and our future debt agreements could limit, our ability to engage in certain activities.” Such limitations may also restrict our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of assets or businesses.

 

We may be subject to risks in connection with acquisitions of properties.

 

The successful acquisition of properties requires an assessment of several factors, including:

 

   

recoverable reserves;

 

   

future oil and natural gas prices and their applicable differentials;

 

   

geological risks;

 

   

access to markets;

 

   

operating costs; and

 

   

potential environmental and other liabilities.

 

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices.

 

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However, these reviews will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.

 

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

 

In order to bring equipment, supplies, water, personnel and produced products to and from certain of our properties, we and/or our contractors must obtain permissions or rights-of-way from other parties, including private property owners and governmental agencies. There is no guarantee that we or our contractors will be able to obtain or continue to obtain those permissions or rights or to obtain them at a reasonable cost. In addition, certain of our properties are subject to land use restrictions, including ordinances, which could limit the manner in which we conduct our business. Although none of our proposed drilling locations associated with proved undeveloped reserves as of December 31, 2017 are on properties currently subject to such land use restrictions, such restrictions may become effective in the future. All of the permissions, rights-of-way, and restrictions discussed above could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs incurred to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and may even be precluded from the drilling of wells.

 

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

 

We do not own any drilling rigs, nor do we own other equipment and supplies that are critical to our continuing ability to drill for and produce oil, gas, and NGLs. We are dependent on access to qualified and competent contractors for such equipment and supplies, as well as the personnel to engage in our drilling and production program. The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which industry has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. We may not be able to renew or obtain new drilling contracts for rigs whose contracts are expiring or are terminated or obtain drilling contracts for our uncontracted new builds. Any delay or inability to secure the personnel, including frac crews, equipment, power, services, resources and facilities access necessary for us to increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

 

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

 

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget.

 

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This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our prior or future commodity derivative activities.

 

Should we fail to comply with all applicable Federal Energy Regulatory Commission (“FERC”) administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

 

Under the Domenici-Barton Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) to impose penalties of up to $1,238,271 per day for each violation for current violations and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC’s annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

 

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

 

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that otherwise require such permits for non-GHG emissions. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in June 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards, but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In February 2018, the EPA finalized amendments to some of the requirements of the June 2016 rule, although the EPA’s reconsideration of other aspects of the rule is ongoing. To the extent implemented, compliance with these rules would require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules would also likely require additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance. Although on September 11, 2018, the EPA issued proposed revisions to the New Source Performance Standards applicable to new and modified oil and gas sources, which would reduce the monitoring obligations for wells and compressor stations, new rules related to the reduction of methane and GHG emissions could result in increased compliance costs on our operations.

 

There have not been significant legislative proposals 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 programs and initiatives have been enacted or are being considered that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs, direct taxation of carbon emissions, or that promote the use of less carbon-intensive fuels.

 

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At the international level, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement (the “Paris Agreement”) that requires member countries to review and “represent a progression” in their intended nationally determined contributions, and set GHG emission reduction goals every five years beginning in 2020. The Paris Agreement entered into force in November 2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from the participating nations to voluntarily limit or reduce future emissions. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs on different terms. In August 2017, the U.S. Department of State provided official notice to the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

 

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. 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, droughts, and other climatic events. Our operations are onshore and not located in coastal or flood-prone regions of the United States, but if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water for our operations and thus could have a material 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 and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations and expect to continue that practice. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued: final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

 

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more

 

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frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this prospectus, these risks are regulated under various state, federal, and local laws. The EPA’s study report did not find a direct link between the action of hydraulically fracturing the well itself and contamination of groundwater resources. The study report does not, therefore, appear to provide a reasonable basis to expect Congress to repeal the exemption for hydraulic fracturing under the SDWA at the federal level.

 

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule includes testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Local governments also 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 development activities, and perhaps even be precluded from drilling wells.

 

Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water, including saltwater, gathered from such activities, which could have a material adverse effect on our business.

 

State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed in other states, for example recent lawsuits in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements on the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a 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 for a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates that such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Oklahoma Corporation Commission also released well completion seismicity guidelines in December 2016 for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, in February 2017, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. It is possible that similar measures could be implemented in the areas where we operate.

 

We dispose of large volumes of produced water, including saltwater, gathered from our drilling and production operations using disposal wells pursuant to permits issued by governmental authorities overseeing

 

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such disposal activities and pursuant to permissions granted by the owners of properties where the disposal wells are located. While these permits are issued in accordance with existing laws and regulations, these legal requirements are subject to change, as are the permissions granted by property owners. Any changes could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities or property owners regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations or changes that restrict our expected ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities, either by limiting disposal volumes, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

 

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

 

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

 

The loss of senior management or technical personnel could adversely affect our operations.

 

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. On May 2, 2018, J.A. (Alan) Townsend, our President and Chief Executive Officer, informed our board of directors of his intent to retire from his position as President and Chief Executive Officer and as a director of the Company. Mr. Townsend continued to serve in his capacity as Director, President and Chief Executive Officer until September 4, 2018, at which point Gary C. Hanna was appointed interim President and Chief Executive Officer while the Company searches for a permanent replacement. Loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

 

Our business is difficult to evaluate because it may be susceptible to the potential difficulties associated with rapid growth and expansion.

 

Our assets have grown rapidly over the last several years. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

 

   

increased responsibilities for our executive level personnel;

 

   

increased administrative burden;

 

   

increased capital requirements; and

 

   

increased organizational challenges common to large, expansive operations.

 

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information contained in this prospectus is not necessarily indicative of the results that may be realized in the future.

 

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Failure to maintain effective internal controls over financial reporting could have a material adverse effect on our business, operating results and stock price.

 

Management concluded that the Company had a material weakness as of December 31, 2017 due to significant deficiencies in the following areas:

 

   

asset retirement obligations estimates;

 

   

timely reconciliation and review of accounts;

 

   

determination of accrued liabilities;

 

   

identification and documentation of related party transactions; and

 

   

depreciation, depletion and amortization calculations.

 

A material weakness also existed at December 31, 2017 related to the timely identification and analysis of the appropriate accounting treatment of complex transactions. This relates to the beneficial conversion feature matter requiring restatement, filed on November 3, 2017, of the Company’s financial statements for the period ended June 30, 2017, identification of an embedded derivative related to the change of control provision in our Series B Preferred Stock, accounting for noncontrolling interest and income taxes. As a result of the error and the related restatement of the Company’s financial statements, and as a result of the material weaknesses identified, our CEO and CFO have concluded that our internal controls over financial reporting continued to be ineffective as of June 30, 2018.

 

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

 

We have regularly sold non-core assets in order to increase capital resources available for other core assets and to create organizational and operational efficiencies. We have also occasionally sold interests in core assets for the purpose of accelerating the development and increasing efficiencies in such core assets. Various factors could materially affect our ability to dispose of such assets in the future, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms we deem acceptable.

 

Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the 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.

 

The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil, natural gas and NGL reserves.

 

The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil, natural gas and NGL reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then-current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

 

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Our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

 

As of June 30, 2018, we have approximately $29.3 million of U.S. federal operating loss carryforwards (“NOLs”), which will begin to expire in 2035. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or a group of shareholders) who are each deemed to own at least 5% of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period.

 

In the event that an ownership change has occurred, or were to occur, utilization of our NOLs in existence at the time of the ownership change would be subject to an annual limitation under Section 382, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382, subject to certain adjustments. Any unused annual limitation may be carried over to later years until they expire.

 

We believe we experienced an ownership change as a result of the Transaction on April 27, 2017, and our NOLs at the time of the Transaction are subject to limitation under Section 382 of the Code, which may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitation were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. To the extent we are not able to offset our future income with our NOLs, this would adversely affect our operating results and cash flows if we attain profitability. Similar rules and limitations may apply for state income tax purposes.

 

We depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

 

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could significantly disrupt our business operations.

 

Our derivative transactions expose us to counterparty credit risk.

 

Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

 

Hedging transactions may limit our potential gains and increase our potential losses.

 

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production, we have entered into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

 

   

our production is less than expected;

 

 

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there is a widening of price differentials between delivery points for our production; or

 

   

the counterparties to our hedging agreements fail to perform under the contracts.

 

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

 

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, then-President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the SEC and the Commodity Futures Trading Commission (or CFTC), along with other federal agencies, to promulgate regulations implementing the new legislation.

 

The CFTC has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding trade reporting, margin, clearing, and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

 

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, 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. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank 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. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

 

Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.

 

The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

 

Changes to state tax laws in response to recently enacted U.S. federal tax legislation.

 

Currently, many states conform their calculation of corporate taxable income to the calculation of corporate taxable income at the U.S. federal level. Due to recently enacted changes to U.S. federal income tax laws, certain states may change or modify the calculation of corporate taxable income at the state level. Any resulting increase in costs due to such changes could have an adverse effect on our financial position, results of operations and cash flows.

 

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Risks Related to Our Indebtedness

 

We may incur substantial additional debt, which could decrease our ability to maintain operations or service existing debt obligations.

 

Subject to the restrictions in our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement (as defined below), we may incur substantial additional debt in the future. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to then-existing debt levels could intensify the operational risks that we now face.

 

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

 

Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our Amended and Restated Credit Agreement and Second Lien Notes or line of credit, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our current and future indebtedness.

 

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement restrict, among other things, our ability to dispose of assets and our use of the proceeds from such disposition. See “—Restrictions in our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement limit, and our future debt agreements could limit, our ability to engage in certain activities.” We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

 

Restrictions in our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement limit, and our future debt agreements could limit, our ability to engage in certain activities.

 

Our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement contain, and our future debt agreements may contain, a number of significant covenants, including restrictive covenants that limit our ability to, among other things:

 

   

incur additional indebtedness;

 

   

be liable in respect of any third-party guaranty;

 

   

incur liens;

 

   

make loans to others;

 

 

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make investments;

 

   

pay dividends or make distributions to third parties;

 

   

liquidate, merge or consolidate with another entity;

 

   

enter into commodity hedges exceeding a specified percentage of our expected production;

 

   

enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness;

 

   

sell properties or assets;

 

   

issue additional shares of capital stock; and

 

   

engage in certain other transactions without the prior consent of the holders of the Second Lien Notes and the Series B Preferred Stock and/or JPMorgan Chase Bank, N.A. and the lenders under the Amended and Restated Credit Agreement.

 

In addition, our Amended and Restated Credit Agreement requires us to maintain the following financial ratios: (1) a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended and Restated Credit Agreement, but excluding non-cash assets) to consolidated current liabilities (excluding non-cash obligations, reclamation obligations to the extent classified as current liabilities and current maturities under the Amended and Restated Credit Agreement), of not less than 1.0 to 1.0, (2) a leverage ratio, which is the ratio of the sum of all of our Total Debt to Annualized EBITDAX (as such terms are defined in the Amended and Restated Credit Agreement) for the four fiscal quarters (or other applicable period) then ended, of not greater than 4.00 to 1.00 and (3) a coverage ratio, which is the ratio of (i) EBITDAX (as defined in the Amended and Restated Credit Agreement) to (ii) the sum of (x) Interest Expense (as such terms are defined in the Amended and Restated Credit Agreement) plus (y) the aggregate amount of Restricted Payments made in cash pursuant to Sections 9.04(a)(iv) and (v) of the Amended and Restated Credit Agreement, during the preceding four fiscal quarters, of not less than 2.5 to 1.0. Failure to do so could result in mandatory or full repayment of the indebtedness. The senior secured revolving credit facility also does not permit us to borrow funds if at the time of such borrowing, we are not in pro forma compliance with the financial covenants.

 

Although as of June 30, 2018 we were in compliance with the current ratio covenant, if we do not sufficiently reduce our capital expenditures in the future or obtain additional financing, including the issuance of additional Series B Preferred Stock, prior to our next borrowing base redetermination date, we may be required to seek a waiver from our lenders with respect to our compliance with our current ratio covenant. There can be no assurance that the lenders will grant a waiver. Our next scheduled redetermination date is April 1, 2019, although we have the right to request a redetermination prior to that date.

 

A breach of any covenant in our Amended and Restated Credit Agreement, including the current ratio covenant, likely would result in a default under the Amended and Restated Credit Agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under our Amended and Restated Credit Agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness may become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. If an event of default occurs under the Amended and Restated Credit Agreement, JPMorgan Chase Bank, N.A. will have the right to proceed against the pledged capital stock and take control of substantially all of our material operating subsidiaries that are guarantors’ assets. The results of such action would have a significant negative impact on our results of operations and financial condition.

 

If we fail to pay dividends on the Series B Preferred Stock in any fiscal quarter, the dividend rate will increase from 10% to 12% per annum on the $1,000 liquidation preference per share of Series B Preferred Stock until such dividends are paid in full. In addition, if the Company fails to pay dividends for three out of four

 

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consecutive fiscal quarters or for six quarters (whether or not consecutive), then a representative appointed by the holders of a majority of the outstanding shares of Series B Preferred Stock shall have the right to appoint one director to our board of directors, and we shall be required to seek the approval of such representative for certain corporate actions, in each case, until three months following the date on which such dividends are paid in full.

 

The restrictions in our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our Amended and Restated Credit Agreement, Certificate of Designations for the Series B Preferred Stock and the Note Purchase Agreement impose on us.

 

Any significant reduction in the borrowing base under our Amended and Restated Credit Agreement as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

 

Our Amended and Restated Credit Agreement limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine at certain periods throughout the year. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan. If we do not furnish the information required for the redetermination by the specified date, the lender may nonetheless redetermine the borrowing base in their sole discretion until the relevant information is received.

 

In the future, we may not be able to access adequate funding under our Amended and Restated Credit Agreement (or a replacement facility) as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

 

Increases in interest rates could adversely affect our business.

 

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Our Amended and Restated Credit Agreement is subject to similar or greater interest rate expenses. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve planned growth and operating results.

 

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Risks Related to the Class A Common Stock and Our Capital Structure

 

We are a holding company. Our sole material asset is our equity interest in Rosehill Operating and we are accordingly dependent upon distributions from Rosehill Operating to pay taxes, make payments under the Tax Receivable Agreement, cover our corporate and other overhead expenses and make payments with respect to our Series A Preferred Stock and Series B Preferred Stock.

 

We are a holding company and have no material assets other than our equity interest in Rosehill Operating. We have no independent means of generating revenue. To the extent Rosehill Operating has available cash, we intend to cause Rosehill Operating to make (i) generally pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay dividends with respect to the Series A Preferred Stock and the Series B Preferred Stock, pay our taxes and to make payments under the Tax Receivable Agreement with Tema and (ii) non-pro rata payments to us to reimburse us for our corporate and other overhead expenses. To the extent that we need funds and Rosehill Operating or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

 

The market price of the Class A Common Stock may decline.

 

Fluctuations in the price of the Class A Common Stock could contribute to the loss of all or part of your investment. The trading price of the Class A Common Stock could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment and the Class A Common Stock may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of the Class A Common Stock may not recover and may experience a further decline.

 

Factors affecting the trading price of the Class A Common Stock may include:

 

   

actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;

 

   

changes in the market’s expectations about our operating results;

 

   

success of competitors;

 

   

our operating results failing to meet the expectation of securities analysts or investors in a particular period;

 

   

changes in financial estimates and recommendations by securities analysts concerning us or our markets in general;

 

   

operating and stock price performance of other companies that investors deem comparable to us;

 

   

our ability to market new and enhanced products on a timely basis;

 

   

changes in laws and regulations affecting our business;

 

   

commencement of, or involvement in, litigation involving us;

 

   

changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

 

   

the volume of securities available for public sale;

 

   

any major change in our board or management;

 

   

sales of substantial amounts of our securities by our directors, executive officers or significant stockholders or the perception that such sales could occur; and

 

   

general economic and political conditions such as recession; interest rate, fuel price, and international currency fluctuations; and acts of war or terrorism.

 

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Many of the factors listed above are beyond our control. In addition, broad market and industry factors may materially harm the market price of the Class A Common Stock irrespective of our operating performance. The stock market in general, and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of our Class A Common Stock and public warrants, which trade on The NASDAQ Capital Market, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to us could depress the price of the Class A Common Stock regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of the Class A Common Stock also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

 

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding the Class A Common Stock adversely, the price and trading volume of the Class A Common Stock could decline.

 

The trading market for the Class A Common Stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts and there can be no assurance that any will cover us in the future. Furthermore, if one or more analysts do cover us and downgrade or provide negative outlook on our stock or our industry, or the stock of any of our competitors, or publishes inaccurate or unfavorable research about our business, the price of the Class A Common Stock could decline. If one or more of these analysts commence and subsequently cease coverage of our business or fail to publish reports on us regularly, we could lose visibility in the market, which in turn could cause our stock price or trading volume to decline.

 

Tema and KLR Sponsor own a significant percentage of our outstanding voting common stock.

 

Tema and KLR Sponsor currently beneficially own approximately 85.7% of our voting common stock and, upon the conversion of our Series A Preferred Stock, will beneficially own approximately 73.1% of our voting common stock. As long as Tema and KLR Sponsor own or control a significant percentage of outstanding voting power, they will continue to have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.

 

The interests of Tema and KLR Sponsor may not align with the interests of our other stockholders. Tema and KLR Sponsor may acquire and hold interests in businesses that compete directly or indirectly with us. Tema and KLR Sponsor may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our second amended and restated certificate of incorporation, amended and restated bylaws and the Shareholders’ and Registration Rights Agreement, dated as of December 20, 2016, by and among the Company, Tema, KLR Sponsor, Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P. (the “SHRRA”), provide that, subject to certain limitations, we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.

 

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We are currently a “controlled company” within the meaning of the NASDAQ listing rules, but may not retain that status in the event that we conduct equity offerings in the future. However, during the phase-in period we may continue to rely on exemptions from certain corporate governance requirements that provide protection to stockholders of other companies.

 

Because Tema and KLR Sponsor control a majority of the combined voting power of all classes of our outstanding voting stock, we have been a “controlled company” under NASDAQ corporate governance listing standards. Under the NASDAQ rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NASDAQ corporate governance requirements, including the requirements that:

 

   

a majority of the board of directors consist of independent directors;

 

   

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

 

   

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

 

In the event that we conduct equity offerings in the future, Tema and KLR Sponsor may cease to control a majority of the combined voting power of all classes of our outstanding voting stock. Accordingly, we may no longer be a “controlled company” within the meaning of the rules of NASDAQ. Under NASDAQ rules, a company that ceases to be a controlled company must comply with the independent board committee requirements as they relate to the nominating and corporate governance and compensation committees on the following phase-in schedule: (1) one independent committee member at the time it ceases to be a controlled company, (2) a majority of independent committee members within 90 days of the date it ceases to be a controlled company and (3) all independent committee members within one year of the date it ceases to be a controlled company. Additionally, NASDAQ rules provide a 12-month phase-in period from the date a company ceases to be a controlled company to comply with the majority independent board requirement. During these phase-in periods, our stockholders will not have the same protections afforded to stockholders of companies of which the majority of directors are independent. Additionally, if, within the phase-in periods, we are not able to recruit additional directors who would qualify as independent, or otherwise comply with NASDAQ rules, we may be subject to enforcement actions by NASDAQ. Furthermore, a change in our board of directors and committee membership may result in a change in corporate strategy and operation philosophies, and may result in deviations from our current growth strategy.

 

The pro forma per share data included in this prospectus excludes the transaction costs attributable to the Transaction and may not be indicative of what our actual financial position or results of operations would have been had the Transaction not occurred.

 

We incurred non-recurring transaction costs that were directly attributable to the Transaction of $2.5 million for the six months ended June 30, 2017 and $2.6 million and $2.8 million for the years ended December 31, 2017 and 2016, respectively. The pro forma per share data included in this prospectus was calculated excluding transaction costs attributable to the Transaction and is presented for illustrative purposes only. The pro forma per share data is not necessarily indicative of what our actual financial position or results of operations would have been had the Transaction not been completed on the dates indicated. See “Prospectus Summary—Summary Historical Financial Information.”

 

Future sales of our Common Stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

 

We may sell additional shares of Class A Common Stock or securities convertible into Class A Common Stock in subsequent public or private offerings. On September 20, 2018, 6,542,368 shares of our Class A Common Stock were outstanding and upon completion of this offering, 12,692,368 shares, or 13,614,868 shares

 

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if the underwriters exercise in full their option to purchase additional shares of Class A Common Stock, will be outstanding.

 

Downward pressure on the market price of our Class A Common Stock that likely will result from sales of our Class A Common Stock issued in connection with the exercise of the warrants for shares of Class A Common Stock or the conversion of the Class B Common Stock or Series A Preferred Stock could encourage short sales of our Class A Common Stock by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. Such sales of our Class A Common Stock could have a tendency to depress the price of the stock, which could increase the potential for short sales.

 

We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

 

The Class A Common Stock are equity interests and are therefore subordinated to our indebtedness and preferred stock.

 

In the event of our liquidation, dissolution or winding up, the Class A Common Stock would rank below our Series A Preferred Stock and Series B Preferred Stock and all secured debt claims against us. As a result, holders of the Class A Common Stock will not be entitled to receive any payment or other distribution of assets upon our liquidation, dissolution or winding up until after all of our obligations to our secured debt holders and to holders of our Series A Preferred Stock and Series B Preferred Stock have been satisfied.

 

Because we currently have no plans to pay cash dividends on our Class A Common Stock, you may not receive any return on investment unless you sell your Class A Common Stock for a price greater than that which you paid for it.

 

We currently do not expect to pay any cash dividends on our Class A Common Stock. Any future determination to pay cash dividends or other distributions on our Class A Common Stock will be at the discretion of the board of directors and will be dependent on our earnings, financial condition, operation results, capital requirements, and contractual, regulatory and other restrictions, including restrictions contained in the senior secured credit facility or agreements governing any existing and future outstanding indebtedness we or our subsidiaries may incur, on the payment of dividends by us or by our subsidiaries to us, and other factors that our board of directors deems relevant.

 

As a result, you may not receive any return on an investment in our Class A Common Stock unless you sell the Class A Common Stock for a price greater than that which you paid for it.

 

Some of our total outstanding shares are restricted from immediate resale but may be sold into the market in the future. This could cause the market price of our Class A Common Stock to drop significantly, even if our business is doing well.

 

As of June 30, 2018, KLR Sponsor and Tema held approximately 85.7% of our issued and outstanding shares of Class A Common Stock, including Class A Common Stock issuable upon exchange of Class B Common Stock. The SHRRA restricts, except in certain circumstances, KLR Sponsor, Tema and permitted transferees 67% of their common stock until two years following the date of consummation of the Transaction. The market price of our Class A Common Stock could decline if the holders of previously restricted shares sell them or are perceived by the market as intending to sell them. Additionally, the Tax Receivable Agreement grants Tema the right to prevent certain dispositions of the assets we acquired in the Transaction for a period of up to three years following the closing of the Transaction.

 

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Additionally, in connection with the Transaction, we issued a total of 95,000 shares of Series A Preferred Stock (convertible into Class A Common Stock) and 9,000,000 warrants (exercisable for shares of Class A Common Stock), and have a total of 25,594,158 warrants outstanding at June 30, 2018. To the extent the Class A Common Stock that is issuable upon conversion or exercise of these securities is sold, the market price of our Class A Common Stock could decline.

 

Holders of our Series B Preferred Stock have certain limited consent rights that could prevent us from taking certain corporate actions, and as a result may adversely affect our business, operating results and stock price.

 

Holders of our Series B Preferred Stock have certain limited consent rights with respect to our ability to take certain corporate actions, including the following:

 

   

the issuance, authorization or creation of any class or series of stock senior to or on parity with the Series B Preferred Stock;

 

   

the incurrence of additional indebtedness, provided that such indebtedness may be incurred if, after giving pro forma effect to the incurrence and any application of the proceeds thereof, we maintain a Leverage Ratio (as defined in the Certificate of Designations) of less than 4.00 to 1.00;

 

   

the issuance or incurrence of high-yield debt, unless the debt (A) does not have an all-in interest rate together with any component of yield greater than the Second Lien Notes (as defined below) and a make-whole provision less favorable than the Second Lien Notes and (B) is used to refinance the Second Lien Notes;

 

   

the entry into any joint venture agreement or issuance of equity securities of our subsidiaries, other than to us or our wholly-owned subsidiaries;

 

   

sales of certain property having a fair market value greater than $15.0 million in any fiscal year and $40.0 million in the aggregate; and

 

   

certain property acquisitions or investments in excess of $15.0 million in any fiscal year and $40.0 million in the aggregate, unless such acquisitions or investments are financed solely using our common equity (or cash proceeds of the issuance of our common equity).

 

The consent rights of the holders of our Series B Preferred Stock could prevent us from obtaining future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities, and as a result may adversely affect our business, operating results and stock price.

 

Anti-takeover provisions contained in our amended and restated charter, as well as provisions of Delaware law, could impair a takeover attempt.

 

Our amended and restated certificate of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that stockholders may consider to be in their best interests. We are also subject to anti-takeover provisions under Delaware law, which could delay or prevent a change of control. Together these provisions may make more difficult the removal of management and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our securities. These provisions include:

 

   

a staggered board providing for three classes of directors, which limits the ability of a stockholder or group to gain control of our board;

 

   

no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;

 

   

the right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director in certain circumstances, which prevents stockholders from being able to fill vacancies on our board of directors;

 

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the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;

 

   

the ability of each of Tema or KLR Sponsor to call a special meeting of stockholders, provided that such person owns 15% or more of the outstanding shares of common stock until the Trigger Date, and thereafter prohibit such ability;

 

   

a prohibition on stockholders calling a special meeting upon and following the Trigger Date, which forces stockholder action to be taken at an annual or special meeting of our stockholders called by the board;

 

   

the requirement that a meeting of stockholders may be called only by the board of directors after the Trigger Date, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;

 

   

providing that after the Trigger Date directors may be removed prior to the expiration of their terms by stockholders only for cause or upon the affirmative vote of 75% of the voting power of all outstanding shares of the combined company;

 

   

a requirement that changes or amendments to the certificate of incorporation or the bylaws must be approved (i) before the Trigger Date, by a majority of the voting power of outstanding common stock of the combined company, which such majority shall include at least 80% of the shares then held by KLR Sponsor and Tema, and (ii) thereafter, certain changes or amendments must be approved by at least 75% of the voting power of outstanding common stock of the combined company; and

 

   

advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.

 

Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.

 

We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In particular, we are required to comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

 

We may be required to make payments under the Tax Receivable Agreement for certain tax benefits that we may claim, and the amounts of such payments could be significant.

 

In connection with the closing of the Transaction, we entered into the Tax Receivable Agreement with Tema. This agreement generally provides for the payment by us to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are deemed to realize in certain circumstances in periods after the Transaction as a result of certain increases in the tax basis in the assets of Rosehill Operating and certain benefits attributable to imputed interest. We will retain the benefit of the remaining 10% of these cash savings.

 

The term of the Tax Receivable Agreement will continue until all tax benefits that are subject to the Tax Receivable Agreement have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control (or the Tax

 

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Receivable Agreement is terminated early due to our breach of a material obligation thereunder), and we make the termination payment specified in the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

 

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Rosehill Operating, and we expect that the payments we will be required to make under the Tax Receivable Agreement will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreement is by its nature imprecise. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income tax rate) to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, are dependent upon significant future events and assumptions, including the timing of the redemptions of Rosehill Operating Common Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of Tema’s tax basis in its Rosehill Operating Common Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rates then applicable, and the portion of our payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis. The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in us or Rosehill Operating.

 

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

 

If we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control or it is terminated early due to our breach of a material obligation thereunder, our obligations under the Tax Receivable Agreement would accelerate and we would be required to make a substantial immediate lump-sum payment. This payment would equal the present value of the hypothetical future payments that could be required to be paid under the Tax Receivable Agreement (determined by applying a discount rate equal to the one-year London Interbank Offered Rate (“LIBOR”) plus 150 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the assumption that we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement and (ii) the assumption that any Rosehill Operating Common Units (other than those held by us) outstanding on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of the future tax benefits to which the termination payment relates.

 

Upon an early termination of the Tax Receivable Agreement, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash tax savings, if any, in respect of the tax attributes subject to the Tax Receivable Agreement. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if the Tax Receivable Agreement had been terminated immediately after June 30, 2018, the estimated termination payments would, in the aggregate, have been approximately $57.5 million (calculated using a discount rate equal to one-year LIBOR plus 150 basis points, applied against an undiscounted liability of $74.6 million). The foregoing number is merely an estimate and the actual payments could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

 

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In the event that we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control, the consideration payable to holders of our Class A Common Stock could be substantially reduced.

 

If we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control, we would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, our payment obligations under the Tax Receivable Agreement will not be conditioned upon Tema having a continued interest in us or Rosehill Operating. Accordingly, Tema’s interests may conflict with those of the holders of our Class A Common Stock. Please read “—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement” and ‘‘Certain Relationships and Related Party Transactions—Agreements Relating to the Transaction—Tax Receivable Agreement.”

 

We will not be reimbursed for any payments made under the Tax Receivable Agreement in the event that any tax benefits are subsequently disallowed.

 

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. Tema will not reimburse us for any payments previously made under the Tax Receivable Agreement if any tax benefits that have given rise to payments under the Tax Receivable Agreement are subsequently disallowed, except that excess payments made to Tema will be netted against payments that would otherwise be made to Tema, if any, after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

 

In certain circumstances, Rosehill Operating will be required to make tax distributions and tax advances to its unitholders, and the tax distributions and tax advances that Rosehill Operating will be required to make may be substantial.

 

Pursuant to the Second Amended LLC Agreement, Rosehill Operating will make generally pro rata cash distributions, or tax distributions, to its unitholders, including us, in an amount sufficient to allow us to pay our taxes and to allow us to make payments under the Tax Receivable Agreement with Tema. In addition to these pro rata distributions, certain Rosehill Operating unitholders will be entitled to receive tax advances in an amount sufficient to allow each such unitholder to pay its respective taxes on such holder’s allocable share of Rosehill Operating’s taxable income. Any such tax advance will be calculated after taking into account certain other distributions or payments received by the unitholders from Rosehill Operating. Under the applicable tax rules, Rosehill Operating is required to allocate net taxable income disproportionately to its members in certain circumstances. Tax advances will be determined based on an assumed individual tax rate and will be repaid upon exercise of Tema’s redemption right or the call right, as applicable.

 

Funds used by Rosehill Operating to satisfy its tax distribution and tax advance obligations will not be available for reinvestment in our business. Moreover, the tax distributions and tax advances Rosehill Operating will be required to make may be substantial, and because of the disproportionate allocation of net taxable income, may exceed the actual tax liability for some of the existing owners of Rosehill Operating.

 

The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.

 

We qualify as an “emerging growth company” as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not

 

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emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year following the fifth anniversary of the date of our initial public offering, (ii) the last day in the fiscal year in which we have total annual gross revenue of at least $1.07 billion (as adjusted for inflation pursuant to SEC rules from time to time), (iii) the date in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, or (iv) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.

 

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accountant standards used.

 

We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

We make forward-looking statements in this prospectus. These forward-looking statements relate to, among other things, expectations for future financial performance, business strategies and expectations for our business. Specifically, forward-looking statements may include statements relating to:

 

   

our future financial performance;

 

   

our ability to realize the anticipated benefits of the White Wolf Acquisition;

 

   

our business strategy;

 

   

our reserves and future operating results;

 

   

our drilling prospects, inventories, projects and programs;

 

   

our ability to replace the reserves we produce through drilling and property acquisitions;

 

   

our financial strategy, liquidity and capital required for our development program;

 

   

our realized oil, natural gas and NGL prices;

 

   

the timing and amount of our future production of oil, natural gas and NGLs;

 

   

our hedging strategy and results;

 

   

our future drilling plans;

 

   

expansion plans and opportunities;

 

   

our competition and government regulations;

 

   

our ability to obtain permits and governmental approvals;

 

   

our pending legal or environmental matters;

 

   

our marketing of oil, natural gas and NGLs;

 

   

our leasehold or business acquisitions;

 

   

our costs of developing our properties;

 

   

general economic conditions;

 

   

credit markets;

 

   

uncertainty regarding our future operating results; and

 

   

other statements preceded by, followed by or that include the words “estimate,” “plan,” “project,” “forecast,” “intend,” “expect,” “anticipate,” “believe,” “seek,” “target” or similar expressions.

 

These forward-looking statements are based on information available as of the date of this prospectus, and current expectations, forecasts and assumptions, and involve a number of judgments, risks and uncertainties. Accordingly, forward-looking statements should not be relied upon as representing our views as of any subsequent date, and we do not undertake any obligation to update forward-looking statements to reflect events or circumstances after the date they were made, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

 

You should not place undue reliance on these forward-looking statements in deciding whether to invest in the Class A Common Stock. As a result of a number of known and unknown risks and uncertainties, our actual results or performance may be materially different from those expressed or implied by these forward-looking statements. Some factors that could cause actual results to differ include those risks described under Risk Factors elsewhere in this prospectus. Moreover, we operate in a very competitive and rapidly changing environment.

 

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New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.

 

Reserve engineering is a process of estimating underground accumulations of oil and natural gas 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 reserve 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 and natural gas that are ultimately recovered.

 

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

 

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

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USE OF PROCEEDS

 

We expect to receive approximately $34.8 million (or approximately $40.2 million if the underwriters’ option to purchase additional shares is exercised in full) of net proceeds from this offering, after deducting underwriting discounts and estimated offering expenses. We anticipate that we will contribute all of the net proceeds from this offering to Rosehill Operating in exchange for a number of Rosehill Operating Common Units equal to the number of shares of Class A Common Stock issued by us in this offering. Rosehill Operating intends to use the net proceeds from this offering to finance its development plan and for general corporate purposes, including to fund potential future acquisitions.

 

We anticipate that we will contribute all of the net proceeds from the exercise of the underwriters’ option to purchase additional shares to Rosehill Operating in exchange for additional Rosehill Operating Common Units. Rosehill Operating intends to use the net proceeds from this offering to finance its development plan and for general corporate purposes, including to fund potential future acquisitions.

 

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PRICE RANGE OF CLASS A COMMON STOCK AND DIVIDEND POLICY

 

Our Class A Common Stock trades on NASDAQ under the symbol “ROSE.” As of September 20, 2018, there were 19 shareholders of record of our Class A Common Stock. The actual number of holders of our Class A Common Stock is greater than the number of record holders, and includes shareholders who are beneficial owners, but whose shares are held in “street name” by brokers and other nominees. On September 20, 2018, the last reported closing sales price of our Class A Common Stock was $8.56 per share.

 

Until the consummation of the Transaction, our Class A Common Stock was listed on NASDAQ under the symbol “KLRE.” Following the Transaction, which was consummated on April 27, 2017, we continued the listing of our Class A Common Stock on NASDAQ under the symbol “ROSE.”

 

The following table sets forth, for the calendar quarter indicated, the high and low sales prices of our Class A Common Stock as reported on NASDAQ for the periods presented. These comparisons may not provide meaningful information to you in determining whether to purchase shares of our Class A Common Stock. You are urged to obtain current market quotations for our Class A Common Stock and to review carefully the other information contained in this prospectus.

 

     Class A Common Stock  
         High              Low      

Fiscal 2016:

     

Quarter ended 3/31/2016(1)

   $ 9.95      $ 9.90  

Quarter ended 6/30/2016

   $ 10.15      $ 9.90  

Quarter ended 9/30/2016

   $ 10.15      $ 9.91  

Quarter ended 12/31/2016

   $ 10.50      $ 10.10  

Fiscal 2017:

     

Quarter ended 3/31/2017

   $ 10.65      $ 10.20  

Quarter ended 6/30/2017

   $ 11.69      $ 7.80  

Quarter ended 9/30/2017

   $ 8.98      $ 5.52  

Quarter ended 12/31/2017

   $ 10.84      $ 7.62  

Fiscal 2018:

     

Quarter ended 3/31/2018

   $ 8.48      $ 5.75  

Quarter ended 6/30/2018

   $ 8.75      $ 5.79  

Quarter beginning 7/1/2018 through 9/20/2018

   $ 9.45      $ 6.45  

 

(1)   Beginning on March 29, 2016.

 

Dividend Policy

 

We have not paid any cash dividends on the our common stock to date and do not currently contemplate paying dividends in the foreseeable future. The payment of cash dividends in the future will be dependent upon our revenues and earnings, if any, capital requirements and general financial condition. The payment of any future cash dividends will be within the discretion of our board of directors at such time.

 

Pursuant to that certain Certificate of Designation for the Series A Preferred Stock (the “Certificate of Designation for the Series A Preferred Stock”) filed with the Secretary of State of the State of Delaware on April 27, 2017, holders of Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends, payable in cash, Series A Preferred Stock, or a combination thereof, in each case, at the sole discretion of the Company, at an annual rate of 8% on the $1,000 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on July 15, 2017.

 

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Pursuant to that certain Certificate of Designation for the Series B Preferred Stock (the “Certificate of Designation for the Series B Preferred Stock”) filed with the Secretary of State of the State of Delaware on December 8, 2017, holders of Series B Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends, payable in cash, or with respect to dividends declared for any quarter ending on or prior to January 15, 2019, a combination of cash and Series B Preferred Stock, in each case, at the sole discretion of the Company, at an annual rate of 10% on the $1,000 liquidation preference per share of the Series B Preferred Stock, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on January 15, 2018.

 

For a summary of the material terms and provisions of our capital stock, see “Description of Capital Stock.”

 

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CAPITALIZATION

 

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2018:

 

   

on an actual basis; and

 

   

as adjusted to give effect to the sale of Class A Common Stock in this offering (using the public offering price of $6.10 per share and assuming no exercise of the underwriters’ option to purchase additional shares) and the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

 

This table should be read in conjunction with, and is qualified in its entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the accompanying notes appearing elsewhere in this prospectus.

 

     As of June 30, 2018  
     Actual     As Adjusted  
     (in thousands, except share
counts and par value)
 

Cash and cash equivalents(1)

   $ 12,855   $ 47,669  
  

 

 

   

 

 

 

Long-term debt, including current maturities:

    

Credit Facility(1)

     145,000       145,000  

10.00% Senior Secured Second Lien Notes due 2023

     100,000       100,000  
  

 

 

   

 

 

 

Total principal amount

   $ 245,000   $ 245,000  
  

 

 

   

 

 

 

Debt issuance cost on 10.00% Senior Second Lien notes due 2023, net

     3,528       3,528  

Discount on 10.00% Senior Second Lien notes due 2023, net

     2,737       2,737  
  

 

 

   

 

 

 

Total debt, net

   $ 238,735   $ 238,735  
  

 

 

   

 

 

 

Mezzanine equity:

    

Series B Preferred Stock, $0.0001 par value; 210,000 shares authorized, 153,630 shares issued and outstanding (Actual); 210,000 shares authorized, 153,630 shares of Series B Preferred Stock issued and outstanding (As Adjusted)

     147,941       147,941  

Stockholders’ equity:

    

Class A Common Stock, $0.0001 par value; 250,000,000 shares authorized, 6,542,368 shares issued and outstanding (Actual); 250,000,000 shares authorized, 12,692,368 shares issued and outstanding (As Adjusted)

     1       1  

Class B Common Stock, $0.0001 par value; 30,000,000 shares authorized, 29,807,692 shares issued and outstanding (Actual); 30,000,000 shares authorized, 29,807,692 shares issued and outstanding (As Adjusted)

     3       3  

Series A Preferred Stock, $0.0001 par value; 150,000 shares authorized, 99,647 shares of Series A Preferred Stock issued and outstanding (Actual); 150,000 shares authorized, 99,647 shares of Series A Preferred Stock issued and outstanding (As Adjusted)

     82,609       82,609  

Additional paid-in capital

     30,630       39,872  

Retained earnings

     7,858     7,858  

Non-controlling interest

     (8,026     17,546  
  

 

 

   

 

 

 

Total stockholders’ equity

   $ 113,075   $ 147,889  
  

 

 

   

 

 

 

Total capitalization

   $ 499,751   $ 534,565  
  

 

 

   

 

 

 

 

(1)   As of August 31, 2018, we had $185 million borrowings outstanding under Amended and Restated Credit Agreement and $11.8 million in cash on hand.

 

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SELECTED HISTORICAL FINANCIAL INFORMATION

 

We have no direct operations and no significant assets other than our ownership interest in Rosehill Operating, an entity of which we act as the sole managing member and of whose Rosehill Operating Common Units we currently own approximately 18.0% (or 33.8% assuming the conversion of our Rosehill Operating Series A preferred units into Rosehill Operating Common Units). Pro forma for the completion of this offering, we expect to own approximately 29.9% of Rosehill Operating Common Units (or 41.7% assuming the conversion of our Series A preferred units in Rosehill Operating into Rosehill Operating Common Units). Rosehill Operating is considered our accounting predecessor. Unless the context otherwise requires, (i) prior to the completion of the Transaction, references to “Rosehill Operating” refer to the assets, liabilities and operations of the business that were contributed to Rosehill Operating Company, LLC in connection with the Transaction and (ii) following the completion of the Transaction, references to “Rosehill Operating” refer to Rosehill Operating Company, LLC.

 

The following table shows our selected historical financial information, and certain pro forma financial information, for the periods indicated. Our selected historical financial information as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015 was derived from our audited historical consolidated financial statements included in this prospectus, and the selected historical financial information of Rosehill Operating as of December 31, 2015 and 2014 and the statement of operations and cash flow data for the year ended December 31, 2014 was derived from audited historical financial statements not included in this prospectus. Our unaudited interim historical financial information as of June 30, 2018 and for the six months ended June 30, 2018 and 2017 was derived from our unaudited interim historical condensed financial statements included elsewhere in this prospectus. The unaudited interim historical financial information has been prepared on a consistent basis with the audited financial statements. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of acquisitions, fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors. In addition, because the historical information for the years ended December 31, 2016, 2015 and 2014 relates to periods prior to the completion of the Transaction and reflects 100% of Rosehill Operating’s financial results, such historical information may not be indicative of our results following the Transaction due in part to our 18% ownership interest in Rosehill Operating.

 

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The selected historical financial information should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the financial statements and accompanying notes included elsewhere in this prospectus.

 

     Six Months Ended
June 30
    Year Ended December 31,  
     2018     2017     2017     2016     2015     2014  
     (unaudited)                          
     (in thousands, except per share data)  

STATEMENTS OF OPERATIONS DATA

            

Total revenues

   $ 136,313     $ 32,166     $ 76,236     $ 34,645     $ 29,487     $ 43,563  

Operating income (loss)

     32,854       1,002       8,894       (8,803     (15,207     (16,504

Net income (loss)

     908       3,000       (11,948     (15,189     (14,820     (19,253

Series A Preferred Stock dividends and deemed dividends

     3,897       8,072       12,936       —         —         —    

Series B Preferred Stock dividends, deemed dividends and return

     11,576       —         2,447       —         —         —    

Net income (loss) attributable to Rosehill Resources Inc. common stockholders

     7,858       (2,743     (8,520     (15,189     (14,820     (19,253

Earnings (loss) per common share:

            

Basic

   $ 1.24     $ (0.47   $ (1.43   $ (2.59   $ (2.53   $ (3.29

Diluted

     (0.70     (0.47     (1.43     (2.59     (2.53     (3.29

Weighted average common shares outstanding

            

Basic

     6,327       5,857       5,945       5,857       5,857       5,857  

Diluted

     36,135       5,857       5,945       5,857       5,857       5,857  

Pro Forma Per Share Data (in thousands, except per share data)(1)

            

Pro forma net income (loss) attributable to Rosehill Resources Inc. common stockholders

            

Basic

   $ 7,858     $ (1,423   $ (8,068   $ (12,355    

Diluted:

   $ (25,264   $ (1,423   $ (8,068   $ (12,355    

Pro forma earnings (loss) per share

            

Basic

   $ 1.24     $ (0.24   $ (1.36   $ (2.11    

Diluted

   $ (0.70   $ (0.24   $ (1.36   $ (2.11    

Pro forma weighted average common shares outstanding

            

Basic

     6,327       5,857       5,945       5,857      

Diluted

     36,135       5,857       5,945       5,857      

CASH FLOW DATA

            

Net cash provided by (used in):

            

Operating activities

   $ 74,595     $ 16,883     $ 37,759     $ 11,461     $ 18,244     $ 25,525  

Investing activities

     (224,639     (45,326     (265,497     (22,164     (16,993     (53,392

Financing activities

     138,217       31,067       243,986       (8,597     17,519       23,457  

OTHER FINANCIAL DATA

            

Adjusted EBITDAX (unaudited)(2)

   $ 84,069     $ 21,699     $ 46,766     $ 18,949     $ 21,743     $ 28,531  

 

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     June 30,
2018
     December 31,  
     2017      2016      2015      2014  
     (unaudited)                              

BALANCE SHEET DATA

              

Total current assets

   $ 49,391      $ 43,543      $ 16,343      $ 33,696      $ 17,792  

Property and equipment, net

     585,080        432,615        123,373        122,873        137,848  

Total assets

     654,291        476,982        139,826        156,903        155,891  

Total current liabilities

     114,945        103,400        14,223        29,165        11,549  

Long-term debt, net

     238,735        93,199        55,000        45,000        75,000  

Mezzanine equity—Series B Preferred Stock

     147,941        140,868        —        —        —    

Total stockholders’ equity / parent net investment

     113,075        122,664        65,220        78,977        56,178  

 

(1)   The pro forma data is provided for illustrative purposes only. We incurred non-recurring transaction costs that were directly attributable to the Transaction of $2.5 million for the six months ended June 30, 2017, and $2.6 million and $2.8 million for the years ended December 31, 2017 and 2016, respectively. Pro forma per share data was recalculated excluding transaction costs. For the six months ended June 30, 2017 and the year ended December 31, 2017, the portion of transaction costs related to our 16% and 17% ownership, respectively, was reduced from the net loss attributable to our common stockholders. We do not expect to incur such transaction expense from our normal operations going forward.
(2)   Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of net income to Adjusted EBITDAX, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measure.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

 

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Information” and our audited historical financial information as of and for the years ended December 31, 2017, 2016 and 2015, and our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2018 and 2017, and the related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside of our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

 

Overview

 

We are an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. We have drilling locations in ten distinct formations in the Delaware Basin in: the Brushy Canyon, Upper Avalon, Lower Avalon, 2nd Bone Spring Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand, 3rd Bone Spring Shale, Wolfcamp A (X/Y), Lower Wolfcamp A and Wolfcamp B, and our goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin. We are actively applying new technologies, such as extended length lateral drilling and enhanced completion techniques, throughout our two core operating areas: the Northern Delaware Basin and the Southern Delaware Basin.

 

We have no direct operations and no significant assets other than our ownership interest in Rosehill Operating, an entity of which we act as the sole managing member and of whose common units we currently own approximately 18.0% (or 33.8%) assuming the conversion of Rosehill Operating Series A preferred units into Rosehill Operating Common Units). Pro forma for the completion of this offering, we expect to own approximately 29.9% of Rosehill Operating Common Units (or 41.7% assuming the conversion of our Series A preferred units in Rosehill Operating into Rosehill Operating Common Units).

 

How We Evaluate Our Operations

 

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

 

   

production volumes;

 

   

operating expenses on a per Barrel of oil equivalent (“Boe”);

 

   

cost of reserve additions from drilling operations; and

 

   

Adjusted EBITDAX as defined under “Non-GAAP Financial Measure.”

 

Market Conditions

 

The oil and natural gas industry is cyclical and commodity prices are highly volatile. Our industry is currently experiencing a recovery from a severe down cycle that began in late 2014 and which persisted through 2016. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to

 

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outpace demand. During 2015, 2016 and early 2017, the global oil supply continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflected the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including the efforts of Russia and Saudi Arabia to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. NGL prices generally correlate to the price of oil. Prices for domestic natural gas began to decline during the third quarter of 2014 and continued to be weak during 2015 through 2017. This decline was primarily due to an imbalance between supply and demand across North America. Thus far into 2018, commodity prices have improved, yet remain volatile, and it is likely that commodity prices will continue to fluctuate due to global supply and demand, inventory supply levels, weather conditions, geopolitical and other factors. Due to these and other factors, commodity prices cannot be accurately predicted.

 

Realized Prices

 

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as NGLs that are extracted from our natural gas during processing. The following table presents our average realized commodity prices before the effects of commodity derivative settlements:

 

     Six Months Ended
June 30,
     Year Ended December 31,  
     2018      2017      2017      2016      2015  

Crude Oil (per Bbl)

   $ 60.40      $ 46.70      $ 48.46      $ 40.52      $ 43.62  

Natural Gas (per Mcf)

     1.91        2.73      $ 2.65      $ 2.23      $ 2.37  

NGLs (per Bbl)

     21.06        16.71      $ 18.31      $ 12.68      $ 12.75  

 

Lower commodity prices in the future could result in impairments of our properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity, or ability to finance planned capital expenditures. Lower oil, natural gas, and NGL prices may also reduce the borrowing base under our credit agreement, which may be determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on our commodity derivatives, which could cause us to experience net losses when oil and natural gas prices rise.

 

A 10% change in our realized oil, natural gas and NGL prices would have changed revenue by the following amounts for the periods indicated:

 

     Six Months Ended
June 30,
     Year Ended December 31,  
     2018      2018      2017      2016      2015  
     (In thousands)      (In thousands)  

Oil sales

   $ 12,462      $ 2,503      $ 6,160      $ 2,481      $ 2,060  

Natural gas sales

     405        371        717        530        491  

NGL sales

     765        343        747        453        398  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total revenues

   $ 13,632      $ 3,217      $ 7,624      $ 3,464      $ 2,949  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

The prices we receive for our products are based on benchmark prices and are adjusted for quality, energy content, transportation fees, and regional price differentials. See “Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues.

 

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Sources of Our Revenues

 

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. The following table shows the components of our revenues for the periods indicated, as well as the percentage each component contributed to total revenue.

 

     Six Months Ended
June 30,
    Year Ended December 31,  
     2018     2018     2017     2016     2015  

Source of revenues(1)(2):

          

Oil sales

     91     78     81     72     70

Natural gas sales

     3       11       9       15       17  

NGL sales

     6       11       10       13       13  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     100     100     100     100     100

 

(1)   Percentage totals may not sum or recalculate due to rounding.

 

(2)   The percentages exclude the effects of commodity derivative settlements.

 

Approximately 91% of total revenues for the six months ended June 30, 2018 and 80%, 70%, and 54% of total revenues for the years ended December 31, 2017, 2016, and 2015, respectively, were from Gateway, a related party.

 

Operational and Financial Highlights for the Six Months Ended June 30, 2018 and 2017 and the Years Ended December 31, 2017, 2016 and 2015

 

Production Results

 

The following table presents sales volumes for our properties for the periods indicated:

 

     Six Months Ended
June 30,
     Year Ended December 31,  
     2018      2017      2017      2016      2015  

Oil (MBbls)

     2,063        536        1,271        612        472  

Natural gas (MMcf)

     2,127        1,357        2,709        2,381        2,074  

NGLs (MBbls)

     363        205        408        358        312  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (MBoe)

     2,781        967        2,131        1,367        1,130  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Average net daily production (Boe/d)

     15,365        5,343        5,838        3,734        3,096  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through drilling as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risk Factors—Risks Related to Our Operations” for a discussion of these and other risks affecting our proved reserves and production.

 

Derivative Activity

 

To achieve a more predictable cash flow and reduce exposure to adverse fluctuations in commodity prices, we have historically used commodity derivative instruments, such as swaps, two-way costless collars, and three-way costless collars, to hedge price risk associated with a portion of our anticipated oil and natural gas production. By removing a significant portion of the price volatility associated with our oil and natural gas

 

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production, we will mitigate, but not eliminate, the potential negative effects of declines in benchmark oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our commodity derivative contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivative contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our commodity derivatives portfolio, we may choose to restructure existing commodity derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. We are under no obligation to hedge a specific portion of our production.

 

A description of our derivative financial instruments is provided below:

 

   

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract value.

 

   

A two-way costless collar is an arrangement that contains a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, we will receive the difference between the floor price and the index price.

 

   

A three-way costless collar is an arrangement that contains a purchased put option, a sold call option and a sold put option based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, we pay the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, we will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

 

   

A purchased put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

 

   

A sold call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

 

Below is a summary of our open commodity derivative positions as of June 30, 2018. Subsequent to June 30, 2018 and through September 21, 2018, the Company added approximately 0.6 million and 0.7 million barrels of crude 3-way collars in 2019 and 2020, respectively, 1.7 million barrels of oil basis swaps in 2019, 7.6

 

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million and 23.5 million gallons of natural gas liquids swaps in 2019 and 2020, respectively, and 1.8 million and 2.1 million mmbtu of natural gas basis swaps in 2019 and 2020, respectively.

 

    2018     2019     2020     2021     2022  

Commodity derivative swaps

         

Oil:

         

Notional volume (Bbls)

    1,438,000       2,664,000       960,000       360,000       300,000  

Weighted average fixed price ($/Bbl)

  $ 55.37     $ 53.59     $ 51.16     $ 50.42     $ 50.12  

Natural Gas:

         

Notional volume (MMBtu)

    1,920,000       2,220,000       1,500,000       1,200,000       1,200,000  

Weighted average fixed price ($/MMbtu)

  $ 3.02     $ 2.88     $ 2.84     $ 2.85     $ 2.87  

Commodity derivative two-way collars

         

Oil:

         

Notional volume (Bbls)

    333,000       601,000       —       —       —  

Weighted average ceiling price ($/Bbl)

  $ 61.01     $ 61.30     $ —     $ —     $ —  

Weighted average floor price ($/Bbl)

  $ 57.30     $ 55.21     $ —     $ —     $ —  

Commodity derivative three-way collars

         

Oil:

         

Notional volume (Bbls)

    —       883,000       2,562,000     —       —  

Weighted average ceiling price ($/Bbl)

  $ —     $ 67.42     $ 67.80   $ —     $ —  

Weighted average floor price ($/Bbl)

  $ —     $ 55.88     $ 56.79   $ —     $ —  

Weighted average sold put option price ($/Bbl)

  $ —     $ 45.88     $ 46.79   $ —     $ —  

Crude oil basis swaps

         

Midland / Cushing:

         

Notional volume (Bbls)

    1,840,000       3,160,000       3,513,600       —       —  

Weighted average fixed price ($/Bbl)

  $ (4.95 )   $ (4.09 )   $ (1.43 )   $ —     $ —  

Argus WTI roll:

         

Notional volume (Bbls)

    1,530,000       —       —       —       —  

Weighted average fixed price ($/Bbl)

  $ 1.14     $ —     $ —     $ —     $ —  

 

See Note 5—Derivative Instruments in the condensed consolidated financial statements for additional information about our derivatives.

 

Principal Components of Our Cost Structure

 

Operating Costs and Expenses

 

Costs associated with producing oil, natural gas, and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells we own.

 

Lease Operating Expenses.    Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water/gas injection, water handling and disposal, compressor rental, and chemicals comprise the most significant portion of our LOE. Certain items, such as direct labor and compressor rental, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For example, repairs to our pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and / or water increases or decreases. For example, we incur water disposal costs in connection with various production-related activities, such as trucking water for disposal until connection can be made to a water disposal well. We are also subject to ad valorem taxes, which is included in LOE, in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

 

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Although we strive to reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another, or we may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence our overall operating costs and could cause fluctuations when comparing LOE on a period to period basis.

 

Production Taxes.    Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state, or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil, natural gas, and NGL revenues.

 

Gathering and Transportation Expense.    Gathering and transportation expense principally consists of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. These costs will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.

 

Depreciation, Depletion, and Amortization.    Depreciation, depletion, and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities, and, as such, we capitalize all costs associated with our development and acquisition efforts and all successful exploration efforts, which are then depleted using the unit of production method. Depreciation of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.

 

Accretion Expense.    Accretion expense is the periodic accreting of the present value of the estimated asset retirement liability to reflect the passage of time.

 

Impairment Expense.    We review our proved properties and unproved leasehold costs for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Impairment is reviewed and recorded on a property-by-property basis. Please read “—Critical Accounting Policies—Impairment of Oil and Natural Gas Properties” for further discussion.

 

General and Administrative Expense.    General and administrative (“G&A”) expense reflects costs incurred for overhead, including compensation for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services, and legal compliance. A portion of these expenses prior to the Transaction have been allocated to us from Tema (on the basis of direct usage when identifiable with the remainder allocated proportionately on a Boe basis).

 

Transaction Expense.    Transaction expense reflects costs incurred in connection with the Transaction. Under the terms of the Business Combination Agreement dated December 31, 2016 (the “Business Combination Agreement”), Tema and Rosemore were entitled to be reimbursed for transaction expenses incurred through the closing of the transaction.

 

Interest Expense, Net.    Interest paid to lenders under the revolving credit facility and other borrowings and interest income earned on cash balances, is reflected in interest expense, net.

 

Non-GAAP Financial Measure

 

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, net, income taxes, DD&A, accretion, impairment of oil and natural gas properties, exploration costs, stock-based compensation, (gains) losses on commodity derivatives excluding net cash receipts (payments) on settled commodity derivatives, one-time costs

 

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incurred in connection with the Transaction, gains and losses from the sale of assets, (gains) losses on asset retirement obligation settlements, and other non-cash operating items. Adjusted EBITDAX is not a measure of net income as determined by U.S. GAAP.

 

Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare our results of operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with U.S. GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that its results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

 

The following table presents an unaudited reconciliation of net loss, the most directly comparable financial measure calculated and presented in accordance with U.S. GAAP, to Adjusted EBITDAX.

 

     Six Months Ended
June 30,
    Year Ended December 31,  
     2018     2017     2017     2016     2015     2014  

Net income (loss) reconciliation to Adjusted EBITDAX (in thousands):

            

Net income (loss)

   $ 908     $ 3,000     $ (11,948   $ (15,189   $ (14,820   $ (19,253

Interest expense, net

     8,529       974       2,532       1,822       3,247       5,469  

Income tax expense (benefit)

     (17,400     273       1,690       148       108       —  

Depreciation, depletion, amortization and accretion

     57,315       17,767       36,091       24,965       23,364       15,967  

Impairment of oil and natural gas properties

     —       —       1,061       —       8,131       27,595  

(Gain) loss on unsettled commodity derivatives, net

     29,045       (3,512     16,553       3,345       735       (2,358

Transaction costs

     —       2,469     2,618       2,834       —       —  

Stock-based compensation

     3,222       —       1,245       —       —       —  

Exploration costs

     2,311       774       1,747       794       960       960  

(Gain) loss on sale of oil and natural gas properties and other property and equipment

     296       (11     (4,995     (50     18       (26

Other (income) expense, net

     (157     (35 )     172       280       —       177  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX (unaudited)

   $ 84,069     $ 21,699     $ 46,766     $ 18,949     $ 21,743     $ 28,531  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

Factors Affecting the Comparability of Our Future Financial Results to the Historical Financial Results of Rosehill Operating

 

Our future results of our operations may not be comparable to the historical results of operations of Rosehill Operating for the periods presented due to the following reasons:

 

Income Taxes.    Rosehill Operating is a limited liability company that is treated as a partnership for U.S. federal income tax purposes and for purposes of certain state and local income taxes. Rosehill Operating is not

 

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subject to U.S. federal income taxes. However, Rosehill Operating is subject to the Texas margin tax at a rate of 0.75%. Any taxable income or loss generated by Rosehill Operating is passed through to and included in the taxable income or loss of its members, including us, on a pro rata basis. We are a corporation and are subject to U.S. federal income taxes, in addition to state and local income taxes with respect to its allocable share of any taxable income or loss of Rosehill Operating, as well as any stand-alone income or loss generated by us.

 

In connection with the closing of the Transaction, we entered into a Tax Receivable Agreement with Tema. This agreement generally provides for the payment by us to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are deemed to realize in certain circumstances in periods after the Transaction as a result of certain increases in the tax basis in the assets of Rosehill Operating and certain benefits attributable to imputed interest. We will retain the benefit of the remaining 10% of these cash savings.

 

Payments will generally be made under the Tax Receivable Agreement as we realize actual cash tax savings in periods after the Transaction from the tax benefits covered by the Tax Receivable Agreement. However, if the Tax Receivable Agreement terminates early, either at our election in connection with certain mergers or other changes of control or as a result of our breach of a material obligation thereunder, we could be required to make a substantial, immediate lump sum payment in advance of any actual cash tax savings. We will be dependent on Rosehill Operating to make distributions to us in an amount sufficient to cover our obligations under the Tax Receivable Agreement.

 

Public Company Expenses.    We incur direct G&A expense as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. These direct G&A expenses are not included in Rosehill Operating’s historical financial results of operations prior to the Transaction date of April 27, 2017.

 

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Results of Operations

 

Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017

 

Oil, Natural Gas and NGL Sales Revenues.    The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average sales prices and volumes:

 

     Three Months Ended
June 30,
               
     2018      2017      Change      Change %  
     (In thousands)         

Revenues:

           

Oil sales

   $ 73,061      $ 11,246      $ 61,815        550

Natural gas sales

     2,308        1,817        491        27  

NGL sales

     5,158        1,602        3,556        222  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total revenues

   $ 80,527      $ 14,665      $ 65,862        449
  

 

 

    

 

 

    

 

 

    

 

 

 

Average sales price(1):

           

Oil (per Bbl)

   $ 60.18      $ 44.45      $ 15.73        35

Natural gas (per Mcf)

     1.68        2.59        (0.91      (35

NGLs (per Bbl)

     22.04        14.70        7.34        50  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (per Boe)

   $ 48.02      $ 30.68      $ 17.34        57
  

 

 

    

 

 

    

 

 

    

 

 

 

Total, including effects of gain (loss) on settled commodity derivatives, net (per Boe)

   $ 42.56      $ 30.65      $ 11.91        39
  

 

 

    

 

 

    

 

 

    

 

 

 

Net production:

           

Oil (MBbls)

     1,214        253        961        380

Natural gas (MMcf)

     1,375        701        674        96  

NGLs (MBbls)

     234        109        125        115  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MBoe)

     1,677        478        1,199        251
  

 

 

    

 

 

    

 

 

    

 

 

 

Average daily net production volume:

           

Oil (Bbls/d)

     13,341        2,779        10,562        380

Natural gas (Mcf/d)

     15,110        7,700        7,410        96  

NGLs (Bbls/d)

     2,571        1,195        1,376        115  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (Boe/d)

     18,429        5,258        13,171        250
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)   Excluding the effects of realized and unrealized commodity derivative transactions unless noted otherwise.

 

The increase in total revenues was due to higher sales volumes and higher average sales prices. The increase in average sales price contributed approximately $19.6 million of the increase in total revenues and the increase in sales volume contributed approximately $46.3 million of the increase in total revenues. The increase in sales volume is primarily attributable to additional wells going into production in 2017 and 2018.

 

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Operating Expenses.    We present per Boe information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis. The following table summarizes our operating expenses for the periods indicated:

 

     Three Months
Ended June 30,
               
     2018      2017      Change      Change %  

Operating expenses (in thousands):

           

Lease operating expenses

   $ 11,225      $ 1,918      $ 9,307        485

Production taxes

     3,841        659        3,182        483  

Gathering and transportation

     1,207        768        439        57  

Depreciation, depletion, amortization and accretion

     36,506        9,536        26,970        283  

Exploration costs

     1,875        457        1,418        310  

General and administrative, excluding stock-based compensation

     6,104        2,204        3,900        177  

Stock-based compensation

     1,826        —          1,826        100  

Transaction costs

     —        1,375        (1,375      (100

(Gain) loss on sale of property and equipment

     163        —          163        100  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $ 62,747      $ 16,917      $ 45,830        271
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating expenses per Boe:

           

Lease operating expenses

   $ 6.69      $ 4.01      $ 2.68        67

Production taxes

     2.29        1.38        0.91        66  

Gathering and transportation

     0.72        1.61        (0.89      (55

Depreciation, depletion, amortization and accretion

     21.77        19.95        1.82        9  

Exploration costs

     1.12        0.96        0.16        17  

General and administrative, excluding stock-based compensation

     3.64        4.61        (0.97      (21

Stock-based compensation

     1.09        —        1.09        100  

Transaction costs

     —        2.88        (2.88      (100

(Gain) loss on sale of property and equipment

     0.10        —          0.10        100  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses per Boe

   $ 37.42      $ 35.40      $ 2.02        6
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Lease operating expense.    The increase in LOE was due to higher sales volumes and higher average LOE rate. The increase in average LOE per Boe contributed approximately $4.5 million of the increase in LOE and the increase in sales volume contributed approximately $4.8 million of the increase in LOE. The increase in sales volume is primarily attributable to additional wells going into production throughout 2017 and 2018. The increase to the LOE rate is primarily due to increases in water disposal costs and equipment rentals.

 

Production taxes.    Production taxes are primarily based on the market value of our wellhead production. The increase was primarily due to increased total revenues. Our total revenues increased by 449% and production taxes increased by 483%. Production taxes as a percentage of total revenues were approximately 4.8% and 4.5% for the three months ended June 30, 2018 and 2017, respectively.

 

Gathering and transportation.    Gathering and transportation expenses are primarily incurred with natural gas and NGL production. The increase to gathering and transportation expenses increased by approximately $0.8 million due to an increase in sales volume of natural gas and NGLs partially offset by a decrease of approximately $0.4 million due to a decrease in gathering and transportation expense per Boe of natural gas and NGLs. The gathering and transportation per Boe decreased due to the disposition of our Barnett Shale assets in the fourth quarter of 2017, which had higher gathering and transportation expenses per Boe.

 

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Depreciation, depletion, amortization and accretion expense.    See the following table for a breakdown of DD&A:

 

     Three Months
Ended June 30,
               
     2018      2017      Change      Change%  

Components of DD&A (in thousands)

           

Depreciation, depletion, and amortization of oil and gas properties

   $ 36,164      $ 9,401      $ 26,763        285

Depreciation of other property and equipment

     189        68        121        178  

Accretion expense

     153        67        86        128  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 36,506      $ 9,536      $ 26,970        283
  

 

 

    

 

 

    

 

 

    

 

 

 

DD&A per Boe

           

Depreciation, depletion, and amortization of oil and gas properties

   $ 21.56      $ 19.67      $ 1.89        10

Depreciation of other property and equipment

     0.11        0.14        (0.03      (21

Accretion expense

     0.10        0.14        (0.04      (29
  

 

 

    

 

 

    

 

 

    

 

 

 

Total DD&A per Boe

   $ 21.77      $ 19.95      $ 1.82        9
  

 

 

    

 

 

    

 

 

    

 

 

 

 

DD&A for oil and gas properties increased by approximately $26.8 million due to an increase of approximately $23.6 million related to an increase in production and an increase of approximately $3.2 million due to an increase in DD&A rate.

 

Exploration costs.    Exploration costs include exploratory seismic expenditures, other geological and geophysical costs, lease rentals, and drilling costs of exploratory wells that are determined to be unsuccessful. The increase for the three months ended June 30, 2018 compared to the same period in 2017 was primarily due to ongoing seismic studies of the acreage we acquired in the White Wolf Acquisition.

 

General and administrative, excluding stock-based compensation.    The increase to G&A expense was primarily due to an increase in payroll and payroll related costs of approximately $2.8 million as a result of an increase in full-time employees. Also, there was an increase of approximately $0.5 million for public company expenses such as board of director fees and expenses, public relations costs, filing fees, audit fees, and legal fees. Furthermore, we incurred an increase of approximately $0.3 million for consultants to assist with various corporate functions such as accounting and human resources. These expenses were not incurred at the same levels, or at all, in periods prior to the Transaction. The remaining increase primarily relates to an increase in general corporate costs such as insurance, office leases, and employee costs.

 

Stock-based compensation.    In April 2017, the stockholders approved the Rosehill Resources Inc. Long-Term Incentive Plan and grants were made starting in July 2017. There were no grants of stock-based compensation outstanding during the three months ended June 30, 2017.

 

Transaction costs.    We incurred transaction expenses of $1.4 million during the three months ended June 30, 2017 related to the Transaction. We did not incur such costs in 2018 and do not expect to incur such costs from our normal operations going forward.

 

(Gain) loss on disposition of property and equipment.    The loss on disposition of property and equipment for the three months ended June 30, 2018 primarily relates to losses on asset retirement obligation settlements.

 

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Other income and expense.    The following table summarizes our other income and expenses for the periods indicated:

 

     Three Months
Ended June  30,
               
     2018      2017      Change      Change %  
     (in thousands)  

Other income (expense):

           

Interest expense, net

   $ (4,662    $ (431    $ (4,231      982

Gain (loss) on commodity derivatives, net

     (19,954      1,303        (21,257      (1,631

Other income (expense), net

     290        153        137        90  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other income (expense)

   $ (24,326    $ 1,025      $ (25,351      (2,473 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

 

Interest expense, net.    The increase was primarily due to interest incurred of $2.5 million on the issuance of $100 million aggregate principal amount of 10.00% Senior Secured Second Lien Notes issued on December 8, 2017. There was also an increase of $1.6 million in interest expense related to our credit facility primarily as a result of an increase in borrowings outstanding during the comparative periods.

 

Loss on commodity derivatives, net.    Net gains and losses on our commodity derivatives are a function of fluctuations in the underlying commodity prices versus fixed hedge prices, time decay associated with options and the monthly settlement of the instruments. The total net loss for three months ended June 30, 2018 is comprised of net losses of $9.2 million on cash settlements and net losses of $10.8 million on mark-to-market adjustments on unsettled positions. The total net gain for the three months ended June 30, 2017 is comprised of net losses of less than $0.1 million on cash settlements and net gains of $1.3 million on mark-to-market adjustments on unsettled positions.

 

Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017

 

Oil, Natural Gas and NGL Sales Revenues.    The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:

 

      Six Months
Ended June 30,
               
      2018      2017      Change      Change %  
     (In thousands)  

Revenues:

           

Oil sales

   $ 124,615      $ 25,029      $ 99,586        398

Natural gas sales

     4,053        3,711        342        9  

NGL sales

     7,645        3,426        4,219       </