S-1/A 1 d200402ds1a.htm S-1/A S-1/A
Table of Contents

As filed with the Securities and Exchange Commission on December 1, 2016.

Registration No. 333-214569

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 3

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

WildHorse Resource Development Corporation

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1311   81-3470246

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification Number)

 

 

9805 Katy Freeway, Suite 400

Houston, TX 77024

(713) 568-4910

 

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

 

 

Jay C. Graham

Chief Executive Officer

9805 Katy Freeway, Suite 400

Houston, TX 77024

(713) 568-4910

 

 

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

 

  Copies to:  

Douglas E. McWilliams

Michael S. Telle

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713) 758-2222

   

Sean T. Wheeler

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

 

 

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   þ  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of Securities

to be Registered

  Amount to be
Registered(1)
  Proposed Maximum
Offering Price Per
Share(2)
  Proposed Maximum
Aggregate Offering
Price(1)(2)
 

Amount of
Registration

Fee(3)

Common stock, par value $0.01 per share

  31,625,000   $21.00   $664,125,000   $76,973

 

 

(1) Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes 4,125,000 additional shares of common stock that the underwriters have the option to purchase.
(2) Estimated solely for the purpose of calculating the registration fee.
(3) The Registrant previously paid $75,335 of the total registration fee in connection with the previous filing of this Registration Statement.

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

The information in this prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state or jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated December 1, 2016

PROSPECTUS

 

 

27,500,000 Shares

 

LOGO

WildHorse Resource Development Corporation

Common Stock

 

 

This is the initial public offering of the common stock of WildHorse Resource Development Corporation, a Delaware corporation. We are offering 27,500,000 shares of common stock.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is expected to be between $19.00 and $21.00 per share. We have been approved to list our common stock on the New York Stock Exchange under the symbol “WRD.”

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Prospectus Summary—Emerging Growth Company Status.”

Investing in our common stock involves risks. See “Risk Factors” on page 23.

 

     Per Share      Total  

Price to the public

   $                        $                    

Underwriting discounts and commissions

   $         $     

Proceeds to us (before expenses)

   $         $     

We have granted the underwriters the option to purchase up to 4,125,000 additional shares of common stock on the same terms and conditions as set forth above to the extent the underwriters sell more than 27,500,000 shares of common stock in this offering.

See “Underwriting (Conflicts of Interest)” beginning on page 175 of this prospectus for additional information regarding underwriter compensation.

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.

The underwriters expect to deliver the shares of common stock on or about                     , 2016.

 

 

Book-Running Managers

 

Barclays   BofA Merrill Lynch   BMO Capital Markets

 

Citigroup   Wells Fargo Securities

 

 

Co-Managers

 

Guggenheim Securities   J.P. Morgan   Raymond James

 

Simmons & Company International   Tudor, Pickering, Holt & Co.

Energy Specialists of Piper Jaffray

 

Capital One Securities   Comerica Securities   Scotia Howard Weil   Wunderlich

Prospectus dated                      , 2016.


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     23   

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     51   

USE OF PROCEEDS

     53   

DIVIDEND POLICY

     54   

CAPITALIZATION

     55   

DILUTION

     57   

SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

     59   

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

     61   

BUSINESS

     101   

MANAGEMENT

     138   

EXECUTIVE COMPENSATION

     143   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     155   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     158   

DESCRIPTION OF CAPITAL STOCK

     162   

SHARES ELIGIBLE FOR FUTURE SALE

     167   

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

     169   

INVESTMENT IN WILDHORSE RESOURCE DEVELOPMENT CORPORATION BY EMPLOYEE BENEFIT PLANS

     173   

UNDERWRITING (CONFLICTS OF INTEREST)

     175   

LEGAL MATTERS

     183   

EXPERTS

     183   

WHERE YOU CAN FIND MORE INFORMATION

     184   

INDEX TO FINANCIAL STATEMENTS

     F-1   

ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS

     A-1   

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. We and the underwriters have not authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Until                     , 2017 (25 days after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

 

   

“WildHorse Development,” “we,” “our,” “us” or like terms refer collectively to WildHorse and Esquisto, together with their consolidated subsidiaries before the completion of our Corporate Reorganization and to WildHorse Resource Development Corporation and its consolidated subsidiaries, including WildHorse, Esquisto and Acquisition Co., as of and following the completion of our Corporate Reorganization. Information expressed on a pro forma basis gives effect to certain transactions more fully described herein as if they had occurred (i) on January 1, 2014 or January 1, 2015, as applicable, for pro forma statements of operations purposes, (ii) on September 30, 2016 for pro forma balance sheet purposes and (iii) on January 1, 2014 or January 1, 2015, as applicable, for production and other operating data. For further details, please read “Prospectus Summary—Summary Pro Forma Financial Data;”

 

   

“WildHorse” or our “predecessor” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries, which owns all of our North Louisiana Acreage;

 

   

“Esquisto” refers (i) for the period beginning January 1, 2014 through June 19, 2014, to the Initial Esquisto Assets, (ii) for the period beginning June 20, 2014 through July 30, 2015, to Esquisto I, (iii) for the period beginning July 31, 2015 through January 11, 2016, to Esquisto I and Esquisto II on a combined basis and (iv) for the period beginning January 12, 2016 through the date hereof, to Esquisto II (which merged with Esquisto I on that date in the Esquisto Merger); Esquisto owns all of our Eagle Ford Acreage;

 

   

“Existing Owners” refers, collectively, to (i) NGP and (ii)(a) in the case of WildHorse, the Management Members that directly or indirectly own equity interests in WildHorse prior to the completion of the Corporate Reorganization and in WildHorse Holdings as of and following the completion of the Corporate Reorganization and (b) in the case of Esquisto, the Management Members that directly or indirectly own equity interests in Esquisto prior to the completion of the Corporate Reorganization and in Esquisto Holdings as of and following the completion of the Corporate Reorganization;

 

   

“Management Members” refers (i) in the case of WildHorse, collectively to the individual founders and employees and other individuals who, together with NGP, initially formed WildHorse and (ii) in the case of Esquisto, collectively to the individual founders and employees and other individuals who initially formed Esquisto;

 

   

“Initial Esquisto Assets” refers to the oil and natural gas properties contributed to Esquisto I in connection with the formation of Esquisto I on June 20, 2014, which contribution we refer to as the “contribution of the Initial Esquisto Assets;”

 

   

“Esquisto I” refers to Esquisto Resources, LLC;

 

   

“Esquisto II” refers to Esquisto Resources II, LLC;

 

   

“Esquisto Merger” refers to the merger of Esquisto I with and into Esquisto II on January 12, 2016;

 

   

“Acquisition Co.” refers to WHE AcqCo., LLC, an entity recently formed to acquire the Burleson North Assets;

 

   

the “Corporate Reorganization” refers to (i) the current owners of WildHorse exchanging all of their interests in WildHorse for equivalent interests in WildHorse Investment Holdings and the current owners of Esquisto exchanging all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) the contribution by WildHorse Investment Holdings to WildHorse Holdings of all of the interests in WildHorse, the contribution by Esquisto Investment Holdings to Esquisto Holdings of all of the interests in Esquisto and the contribution by the current owner of Acquisition Co. of all its interests in Acquisition Co. to Acquisition Co. Holdings, (iii) the issuance of management incentive units by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings to certain of our officers

 

ii


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and employees as described in this prospectus and (iv) the contribution by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings to us of all of the interests in WildHorse, Esquisto and Acquisition Co., respectively, in exchange for shares of our common stock (prior to and in connection with the issuance of shares of common stock in this offering), as described more fully in “Prospectus Summary—Corporate Reorganization;”

 

   

“WildHorse Holdings” refers to WHR Holdings, LLC, a limited liability company formed to own a portion of our common stock following the Corporate Reorganization;

 

   

“WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC, a limited liability company formed to own all of the outstanding equity interests in WildHorse Holdings other than certain management incentive units to be issued by WildHorse Holdings in connection with this offering as further described elsewhere in this prospectus;

 

   

“Esquisto Holdings” refers to Esquisto Holdings, LLC, a limited liability company formed to own a portion of our common stock following the Corporate Reorganization;

 

   

“Esquisto Investment Holdings” refers to Esquisto Investment Holdings, LLC, a limited liability company formed to own all of the outstanding equity interests in Esquisto Holdings other than certain management incentive units to be issued by Esquisto Holdings in connection with this offering as further described elsewhere in this prospectus;

 

   

“Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC, a limited liability company formed to own a portion of our common stock following the Corporate Reorganization;

 

   

“North Louisiana Acreage” refers to our acreage in North Louisiana in and around the highly prolific Terryville Complex, which has been historically owned and operated by WildHorse, and where we primarily target the overpressured Cotton Valley play;

 

   

“Terryville Complex” refers to the play located primarily in Lincoln Parish, Louisiana, and northern Jackson Parish, Louisiana;

 

   

“RCT Area” refers to our Ruston-Choudrant-Tremont acreage within the Terryville Complex located primarily in Lincoln Parish, Louisiana;

 

   

“Weyerhaeuser Area” refers to the acreage that we have the right to lease within the Terryville Complex located in northern Jackson Parish, Louisiana, which acreage is included in our acreage in this prospectus (see “Business—Reserve Data—Acreage);

 

   

“Eagle Ford Acreage” refers to our acreage in the northern area of the Eagle Ford Shale in Southeast Texas, which has historically been owned and operated by Esquisto;

 

   

“Comstock Assets” refers to certain producing properties, undeveloped acreage and water assets Esquisto II acquired from a wholly owned subsidiary of Comstock Resources, Inc. in July 2015, which acquisition we refer to as the “Comstock Acquisition;”

 

   

“Burleson North Assets” refers to certain producing properties and undeveloped acreage that Acquisition Co. expects to acquire from Clayton Williams Energy, Inc. prior to or contemporaneously with the closing of this offering, which acquisition is referred to as the “Burleson North Acquisition;”

 

   

“Acquisitions” refers to the acquisitions described in “Prospectus Summary—Recent Developments,” including the Burleson North Acquisition; and

 

   

“NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WildHorse, Esquisto and Acquisition Co.

We have also included a glossary of some of the oil and natural gas industry terms used in this prospectus in Annex A to this prospectus.

 

iii


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Presentation of Financial and Operating Data

Unless otherwise indicated, the historical financial information presented in this prospectus is that of WildHorse, our predecessor for accounting purposes. The pro forma financial information presented in this prospectus treats the contribution to us of WildHorse and Esquisto in connection with our Corporate Reorganization as a reorganization of entities under common control as if it had occurred on January 1, 2014. Because WildHorse and Esquisto have been under common control since February 2015, once we file a balance sheet after this offering that reflects the completed Corporate Reorganization, prior period financial statements will be retroactively recast to be presented on a combined basis to include the results of Esquisto for periods during which Esquisto was under common control with WildHorse. Please see “Prospectus Summary—Corporate Reorganization” and the unaudited pro forma financial statements included elsewhere in this prospectus.

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of our predecessor and Esquisto on a combined basis as of the dates and for the periods presented. Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and drilling location data is presented in this prospectus as of September 30, 2016. Further, unless indicated otherwise or the context otherwise requires, references to our acreage, drilling locations, working interest and well counts as of September 30, 2016 in this prospectus are adjusted to give effect to the Acquisitions described in “Prospectus Summary—Recent Developments.” Unless otherwise noted, references to production volumes refer to sales volumes.

Certain amounts and percentages included in this prospectus have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, we and the underwriters have not independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our common stock. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the related notes to those financial statements, before investing in our common stock. The information presented in this prospectus assumes an initial public offering price of $20.00 per share (the midpoint of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional shares of our common stock has not been exercised. Further, unless indicated otherwise or the context otherwise requires, references to our acreage, drilling locations, working interest and well counts as of September 30, 2016 in this prospectus are adjusted to give effect to the Acquisitions described in “—Recent Developments.” You should read “Risk Factors” for information about important risks that you should consider carefully before investing in our common stock. Certain common used terms are defined in “Commonly Used Defined Terms” or in the glossary included in this prospectus as Appendix A.

WildHorse Development

We are a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in Southeast Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In Southeast Texas, we operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale (our “Eagle Ford Acreage”), which is one of the most active shale trends in North America. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the overpressured Cotton Valley play (our “North Louisiana Acreage”).

We were formed by our management and technical teams and affiliates of Natural Gas Partners (“NGP”), a family of energy-focused private equity investment funds. Prior to our formation, the founding members of our management and technical teams successfully built and sold multiple NGP-sponsored oil and natural gas assets in and around the location of our acreage. Our Chief Executive Officer, Jay C. Graham, our President, Anthony Bahr, and other members of our management team, have significant experience across our acreage. Messrs. Graham and Bahr co-founded one of the predecessors to, and Mr. Graham served as Chief Executive Officer of, Memorial Resource Development Corp. (“MRD”), which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Certain members of our technical team have also been actively involved in drilling in and around our Eagle Ford Acreage since 2008.

Since we commenced operations in 2013, our management and technical teams have successfully executed our development program, growing our acreage position to approximately 375,000 net acres. We have also grown our production from 4.5 MBoe/d for the three months ended March 31, 2014 to approximately 14.0 MBoe/d for the three months ended September 30, 2016, representing a compound annual growth rate (“CAGR”) of approximately 57%, as described below, and our production for the three months ended September 30, 2016 was 17.9 MBoe/d after giving pro forma effect to the Acquisitions.

As of September 30, 2016, we had assembled a total leasehold position of approximately 375,000 net acres across our expanding acreage, including approximately 267,000 net acres in the Eagle Ford and approximately 108,000 net acres in North Louisiana. We have identified a total of approximately 4,391 gross (2,298 net) drilling locations across our acreage, with further upside potential given the multiple stacked pay zones across much of our acreage. Based on our 2017 drilling program, our identified locations represent an inventory of approximately 46 years.

 



 

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Table of Contents

On our Eagle Ford Acreage, our horizontal drilling locations target the Eagle Ford Shale in Burleson and Lee Counties and the Austin Chalk in Washington County. To date, our drilling program has predominantly targeted our Eagle Ford locations in Burleson County. While not included in our estimate of future horizontal drilling locations, we believe significant additional locations may also exist in the Austin Chalk trend in Burleson County and the Eagle Ford in Washington County. On our North Louisiana Acreage, our horizontal drilling locations target the Upper Red, Lower Red and Upper Deep Pink zones in the RCT and Weyerhaeuser Areas in the overpressured Cotton Valley formation in the Terryville Complex. To date, our drilling program has predominantly targeted our Upper Red locations in the RCT Area. While not included in our estimate of future horizontal drilling locations, we believe additional locations may also exist in additional Cotton Valley intervals across our North Louisiana Acreage.

The following chart provides information regarding our production growth since the first quarter of 2014:

 

 

LOGO

 

 

(1) Includes production attributable to the Comstock Assets acquired in July 2015 for all periods presented.
(2) Compound annual growth rate, or CAGR, represents a calculation of the average annual compounded growth rate of our average daily production from the first quarter of 2014 to the third quarter of 2016 by comparing our average daily production for the third quarter of 2016 to our average daily production for the first quarter of 2014. The calculation assumes that the growth rate derived from the calculation is even across the periods covered by the calculation and does not take into account any fluctuations in our production for any periods other than the two periods used to calculate the CAGR. Accordingly, the use of CAGR may have limitations, particularly in situations where there are substantial fluctuations in production between the periods used to make the calculation. For a more detailed description of how CAGR is calculated, please see the glossary included in this prospectus as Appendix A.

 



 

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Our Drilling Program and Completion Techniques

Our primary objective is to deliver shareholder value through accretive growth in reserves, production and cash flow by developing and expanding our significant portfolio of drilling locations. We believe that our recent well results demonstrate that many of our wells are capable of producing attractive single-well rates of return that are competitive with many of the top performing basins in the United States. We are focused on generating shareholder value by drilling wells with high rates of returns and increasing estimated ultimate recoveries (“EURs”) while driving drilling, completion and operating efficiencies. Our technical expertise has resulted in cost efficiency gains as well as increased hydrocarbon recovery from our wells. For example, in our Eagle Ford Acreage, due to new drilling technologies and improved procedures, on average we were able to drill twice as many wells per rig during the nine months ended September 30, 2016 as we were able to drill during 2014. Additionally, due to improvements in well completions in our Eagle Ford Acreage, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot for our wells completed using Generation 1 hydraulic fracturing design to 98 Boe per foot for our wells completed using Generation 3 hydraulic fracturing design.

In July 2015, we reduced our drilling program in our North Louisiana Acreage to one rig in response to low commodity prices and continued operating a one-rig drilling program through February 2016. Similarly, in early October 2015, we reduced our drilling program in our Eagle Ford Acreage to one rig, which we ran until February 2016, at which point we ceased drilling due to the commodity price environment. We are currently running a one-rig program in our Eagle Ford Acreage and we intend to add an additional rig in our North Louisiana Acreage in late 2016. We intend to add four additional rigs during the remainder of 2017 in order to run a six-rig program by the end of 2017 with four rigs drilling in our Eagle Ford Acreage and two rigs drilling in our North Louisiana Acreage.

The tables below detail certain information on estimated ultimate recoveries (“EUR”) and production for wells we have drilled to date. Please see “Business—Our Drilling Program” for more detail on our wells drilled in our Eagle Ford Acreage and North Louisiana Acreage.

Eagle Ford Wells(1)

 

Completion Technique

 

Well
Count

   

Lateral
Length
(Feet)

   

EUR
(Mboe)
(2)

   

EUR
(Mboe/
1000’)(2)

   

Days
Pro-
ducing

   

Cumu-
lative
Prod.
(MBoe)(3)

    Gross Wellhead Flow Rates
After Processing  (Boe/d)(3)(4)
   

D&C
($MM)(5)

   

D&C
($/Lat
Foot)(5)

   

%

EUR
Liq

   

%

EUR
Oil

 
                     
             

0-30

   

0-90

   

91-180

   

181-360

         

Generation 1

    7        6,225        443        76        739        155        745        568        297        177        13.5        2,958        88     71

Generation 2

    15        6,447        523        81        401        122        611        508        318        216        7.1        1,111        87     69

Generation 3

    9        6,739        633        98        145        67        743        492        481          6.2        966        93     78

 

(1) Information included in this table represents our average well results in our Eagle Ford Acreage for each of our Generation 1, Generation 2 and Generation 3 completion techniques. For a description of the differences in completion techniques, please see “Business—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.” All wells drilled in our Eagle Ford Acreage have been located in our Burleson Main area.
(2) EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of June 30, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil/condensate and gas.
(3) Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.
(4) The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.
(5) Includes all wells drilled and completed as of September 30, 2016. Drilling and completion (“D&C”) costs exclude land costs and title fees.

 



 

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North Louisiana Wells

Wells Drilled in Terryville Complex

 

Well Name

 

Formation

   

Completion
Type(1)

   

Lateral
Length
(Feet)

   

EUR
(Bcfe)(2)

   

EUR
(BCFE/
1000’)(2)

   

First Pro-
duction

   

Days
Pro-
ducing

   

Cumu-
lative
Prod.
(Bcfe)(3)

   

Gross Wellhead Flow
Rates (MMcfe/d)(3)(4)

   

D&C
($MM)(5)

   

D&C
($/Lat
Foot)(5)

   

%

EUR

Gas

 
                       
                  0-30     0-90     91-
180
    181-
360
       

Taylor 13 12 H-1

    Upper Red        Gen 1        6,796        20.4        3.0        3/6/2015        575        5.0        21.8        17.7        9.6        6.7        14.8        2,180        98

Pipes 14 11 HC-1

    Upper Red        Gen 1        8,221        2.3        0.3        5/19/2015        501        0.9        5.4        4.0        2.1        1.2        18.3        2,220        97

Spillers 18 7 HC-1

    Upper Red        Gen 1        8,884        16.6        1.9        7/13/2015        446        3.7        19.4        15.0        8.6        6.2        11.6        1,303        98

Rounsaville 21 16 HC-1

    Upper Red        Gen 1        4,633        0.3        0.1        8/21/2015        407        0.4        1.5        1.3        1.1          11.3        2,443        99

Surline 13 12 HC-1

    Lower Red        Gen 1        7,210        0.3        0.0        9/3/2015        394        0.4        1.6        1.3        1.1          12.9        1,789        98

Ates 18 7 HC-1

    Upper Red        Gen 2        6,705        12.7        1.9        11/17/2015        319        2.5        16.0        12.4        7.2          11.2        1,677        98

Smelley 15 22 H-1

    Upper Red        Gen 2        8,410        16.4        1.9        12/3/2015        303        2.8        17.0        13.6        7.8          12.9        1,536        97

Taylor 13 12 H-2

    Upper Red        Gen 1        4,594        5.9        1.3        1/8/2016        267        1.1        8.6        6.2        3.3          8.3        1,814        98

Pruitt 16 21 HC-1

    Upper Red        Gen 1        9,102        10.8        1.2        3/25/2016        190        1.3        10.4        8.6            11.9        1,304        98

 

(1) For a description of the differences in completion techniques, please see “Business—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”
(2) EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensate and gas.
(3) Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.
(4) The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.
(5) Includes wells drilled and completed as of September 30, 2016 in the Terryville Complex. D&C costs exclude land costs and title fees.

 

Average(1)

 

Well Count

   

Lateral
Length
(Feet)

    EUR
(Bcfe)(2)
    EUR
BCFE/
1000’(2)
   

Days
Pro-
ducing

   

Cumu-
lative
Prod.
(Bcfe)(3)

   

Gross Wellhead Flow
Rates

(MMcfe/d)(3)(4)

   

D&C
($MM)(5)

   

D&C
($/Lat
Foot)(5)

   

%

EUR

Gas

 
                   

Completion Technique

              0-30     0-90     91-
180
    181-
360
       

Generation 1

    7        7,063        8.1        1.1        397        1.8        9.8        7.7        4.3        4.7        12.7        1,865        98

Generation 2

    2        7,558        14.5        1.9        311        2.6        16.5        13.0        7.5          12.1        1,606        97

 

(1) Information included in this table represents our average well results for wells drilled to date in the Terryville Complex in North Louisiana for each of our Generation 1 and Generation 2 completion techniques. For a description of the differences in completion techniques, please see “Business—Our Drilling Program” and “Appendix A: Glossary of Oil and Natural Gas Terms.”
(2) EUR represents the sum of total gross remaining proved reserves attributable to each location in our reserve report as of June 30, 2016 and cumulative sales from such location as of such date. EUR is shown on a combined basis for oil/condensate and gas.
(3) Production data is through September 30, 2016 and shown gross on a combined basis for oil/condensate and gas. Results only include wells with the applicable number of days of production.
(4) The 30-day flow rates consist of the peak 30 days of production. The first day of the peak 30 days is considered day 1 for subsequent flow rates.
(5) Includes wells drilled and completed as of September 30, 2016 in the Terryville Complex. D&C costs exclude land costs and title fees.

 



 

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Our Acreage and Drilling Locations

The table below provides a summary of our net acreage, average working interest, average net revenue interest and horizontal drilling locations as of September 30, 2016:

 

     Acreage     Horizontal Drilling
Locations(3)(4)
 
     Net Acreage      Average
WI %(1)
    Average
NRI %(2)
      Gross            Net      

Eagle Ford

     266,501         82     64     2,977         1,650   

North Louisiana(5)

     108,437         74     57     1,414         648   
  

 

 

        

 

 

    

 

 

 

Total

     374,938         79     62     4,391         2,298   
  

 

 

        

 

 

    

 

 

 

 

(1) Represents our weighted average working interest across our acreage position.
(2) Represents our weighted average net revenue interest across our acreage position.
(3) Please see “Business—Our Properties—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors—Risks Related to Our Business—Our identified 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 substantial amount of capital that would be necessary to drill such locations.”
(4) We expect to operate 2,511 gross (1,943 net) of our 4,391 gross (2,298 net) horizontal drilling locations, of which 1,890 gross (1,509 net) are located on our Eagle Ford Acreage and 621 gross (434 net) are located on our North Louisiana Acreage. We have an approximate 80% and 70% average working interest in our operated horizontal drilling locations in our Eagle Ford and North Louisiana Acreage, respectively.
(5) Includes acreage we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company. See “Business—Reserve Data—Acreage.”

 



 

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Our extensive inventory of locations in East Texas primarily targets the Eagle Ford Shale. We subdivide our Burleson County acreage areas based on our assessment of depth and reservoir characteristics. To date, all of our drilling activity has been focused in our Burleson Main area; however, we own working interests in producing wells in each of the other areas and in our Eagle Ford Acreage. Our Burleson North acreage represents the acreage we intend to acquire from Clayton Williams Energy, Inc. prior to or contemporaneously with the closing of this offering. In North Louisiana, we target multiple horizons within the lower Cotton Valley including the Upper and Lower Red as well as the Upper Deep Pink. The following table provides information regarding our gross and net horizontal drilling locations by area as of September 30, 2016:

 

     Net Horizontal Drilling Locations      Gross Horizontal
Drilling
Locations
 
     Proved      Probable      Possible      Management      Total      Total  

Eagle Ford:

                 

Burleson Main

     103         165         295         68         631         1,331   

Burleson North

     —           —           —           670         670         670   

Burleson West

     6         23         26         5         60         225   

Burleson South

     2         4         16         38         59         292   

Washington County

     2         7         4         —           12         36   

Lee County

     6         12         120         81         218         423   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     117         211         461         862         1,650         2,977   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

North Louisiana:

                 

RCT

                 

Upper Red

     7         15         108         31         161         308   

Lower Red

     —           —           72         94         166         319   

Upper Deep Pink

     —           —           45         122         167         320   

Weyerhaeuser

                 

Upper Red

     —           —           36         27         64         205   

Lower Red

     —           —           36         27         64         205   

Bear Creek

     —           —           26         2         28         57   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total North Louisiana

     7         15         323         303         648         1,414   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 



 

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Our Reserve Information

We believe we have substantial reserves. The following table summarizes the estimated net proved, probable and possible oil, natural gas and NGL reserves of WildHorse and Esquisto on a combined basis as of June 30, 2016 without giving effect to any of the Acquisitions. Cawley, Gillespie & Associates (“Cawley”), our independent petroleum engineer, prepared Esquisto’s reserves estimates and audited WildHorse’s reserves estimates.

 

     Estimated Total Proved Reserves  
     Oil
(MBbls)
     Natural
Gas
(MMcf)
     NGLs
(MBbls)
     Total
(MBoe)
     %
Liquids
     %
Developed
 

Eagle Ford

     49,003         26,518         7,269         60,692         93%         21%   

North Louisiana

     703         274,246         306         46,717         2%         49%   
  

 

 

    

 

 

    

 

 

    

 

 

       

Total

       49,706            300,764           7,575         107,409         53%         33%   
  

 

 

    

 

 

    

 

 

    

 

 

       
     Estimated Total Probable Reserves         
     Oil
(MBbls)
     Natural
Gas
(MMcf)
     NGLs
(MBbls)
     Total
(MBoe)
     %
Liquids
        

Eagle Ford

     60,675         26,758         7,439         72,574         94%      

North Louisiana

     612         164,640         —           28,052         2%      
  

 

 

    

 

 

    

 

 

    

 

 

       

Total

       61,287            191,398           7,439         100,626         68%      
  

 

 

    

 

 

    

 

 

    

 

 

       
     Estimated Total Possible Reserves         
     Oil
(MBbls)
     Natural
Gas
(MMcf)
     NGLs
(MBbls)
     Total
(MBoe)
     %
Liquids
        

Eagle Ford

     105,989         46,761         12,887         126,669         94%      

North Louisiana

     3,953         1,063,042         —           181,127         2%      
  

 

 

    

 

 

    

 

 

    

 

 

       

Total

     109,942         1,109,803         12,887         307,796         40%      
  

 

 

    

 

 

    

 

 

    

 

 

       

Business Strategies

To achieve our primary objective of delivering shareholder value, we intend to execute the following business strategies:

Grow production, reserves and cash flow through the development of our extensive drilling inventory. We believe our extensive inventory of drilling locations in the Eagle Ford and the overpressured Cotton Valley formation in and around the Terryville Complex, combined with our operating expertise, will enable us to continue to deliver accretive production, reserves and cash flow growth and create shareholder value. We have identified a total of approximately 4,391 gross (2,298 net) drilling locations across our acreage, with further upside potential given the multiple stacked pay zones across much of our acreage in addition to potential downspacing. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.

 



 

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Maximize returns by optimizing drilling and completion techniques and improving operating efficiencies. Our management is intently focused on driving efficiencies in the development of our resource base by maximizing our hydrocarbon recovery per well while minimizing our drilling, completion and operating costs. To achieve these efficiencies, we focus on:

 

   

minimizing the costs of drilling and completing horizontal wells through our knowledge of the target formations, pad drilling and reduced drilling times;

 

   

maximizing EURs through advanced drilling, completion and production techniques, such as by optimizing lateral lengths, the number of hydraulic fracturing stages and perforation intervals, water and proppant volumes, fluid chemistry, choke management and the strategic use of artificial lift techniques;

 

   

maximizing our cash flows by targeting specific areas within our balanced portfolio of oil and natural gas drilling opportunities based on the existing commodity price environment; and

 

   

minimizing operating costs through our experience in efficient well management.

In our Eagle Ford Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 67%, from $2,958 per foot for our wells completed using Generation 1 hydraulic fracturing design to approximately $966 per foot for our wells completed using Generation 3 hydraulic fracturing design, in part by drilling our last 18 wells in an average of approximately 11 days. Additionally, as we have transitioned our completion techniques in our Eagle Ford Acreage from Generation 1 to Generation 3 hydraulic fracturing designs, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot to 98 Boe per foot. In our North Louisiana Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 22%, from approximately $1,987 per foot for the nine months ended September 30, 2015 to approximately $1,559 per foot for the nine months ended September 30, 2016. Our drilling and completion cost reductions coupled with our completion design improvements are generating enhanced single-well recoveries and attractive returns in the current commodity environment, and we believe we can further optimize our results through these and other technologies across our acreage position.

Capture additional horizontal development opportunities on current acreage. Our existing asset base provides numerous opportunities for our management team to create shareholder value by increasing our inventory beyond our currently identified drilling locations. Based on results from our horizontal drilling program and those of offset operators, including offset production trends, mud logs, 2-D and 3-D seismic, well data analysis and geologic trend mapping, we believe our acreage has multiple productive zones providing significant upside potential to our current inventory of identified drilling locations. We have excluded from our identified drilling locations potential opportunities associated with downspacing and with additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County, (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage and (iv) additional Cotton Valley intervals across our North Louisiana Acreage.

Utilize extensive acquisition and technical expertise to grow our core acreage position. We have a demonstrated track record of identifying and cost effectively acquiring attractive resource development opportunities, including the Acquisitions. To date, our management and technical teams have completed numerous acquisitions, and we expect to continue to identify and opportunistically lease or acquire additional acreage and producing assets to add to our multi-year drilling inventory. We have followed a geologically driven strategy to establish large, contiguous leasehold positions in our two basins and strategically expand those positions through bolt-on acquisitions over time. We believe our Eagle Ford and North Louisiana Acreage create a platform upon which we can add value by acquiring additional acreage and incremental drilling locations near our current acreage. In this regard, NGP and its affiliates are not limited in their ability to compete with us for future acquisitions, and we do not expect to enter into any agreements or arrangement to apportion future opportunities between us, on the one hand, and NGP and its affiliates, on the other hand.

 



 

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Maintain a disciplined, growth-oriented financial strategy. We prudently manage our liquidity and leverage levels by monitoring cash flow, capital spending and debt capacity, which, being a two-basin company, we believe will allow us to strategically deploy capital among projects across our acreage. After giving effect to this offering and the use of the proceeds based on the midpoint of the price range set forth on the cover of this prospectus (including the repayment and termination of the WildHorse revolving credit facility, the Esquisto revolving credit facility and the notes payable by Esquisto to its members), we estimate that we will have approximately $331.2 million of available borrowing capacity under our new revolving credit facility. We intend to fund our growth primarily with internally generated cash flows while maintaining ample liquidity and access to the capital markets, which we believe will allow us to accelerate our development program and maximize the present value of our resource potential. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations, enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities.

Business Strengths

We believe that the following strengths will allow us to successfully execute our business strategies.

Extensive, contiguous acreage position in two of North America’s leading oil and gas plays. We own an extensive and substantially contiguous acreage position targeting two of the premier plays in North America, the Eagle Ford Shale and the overpressured Cotton Valley formation in and around the Terryville Complex. As of September 30, 2016, we had approximately 375,000 net acres and, as of June 30, 2016, we had 107 MMBoe of proved reserves (46% oil, 47% natural gas and 7% NGLs), 101 MMBoe of probable reserves (61% oil, 32% natural gas and 7% NGLs) and 308 MMBoe of possible reserves (36% oil, 60% natural gas and 4% NGLs) across our acreage. We believe that our recent well results demonstrate that many of the wells on our high-quality acreage are capable of producing attractive single-well rates of return that are competitive with many of the top performing basins in the United States. Furthermore, the location of our acreage provides us with lower operating costs and better realized pricing than other companies operating in different basins around the country due to our acreage’s proximity to the end markets for oil, natural gas and NGLs.

Multi-year inventory of drilling opportunities across our acreage position. We have identified approximately 4,391 gross (2,298 net) drilling locations across our acreage position, providing us with approximately 46 years of drilling inventory based on our 2017 drilling program. On our Eagle Ford Acreage, our horizontal drilling locations target the Eagle Ford Shale in Burleson and Lee Counties and the Austin Chalk in Washington County, and on our North Louisiana Acreage, our horizontal drilling locations target the Upper Red, Lower Red and Upper Deep Pink zones in the RCT and Weyerhaeuser Areas in the overpressured Cotton Valley formation in the Terryville Complex. In addition, we believe our acreage position includes a number of additional areas and zones that are prospective for hydrocarbons. For example, we believe we may identify additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County, (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage and (iv) additional Cotton Valley intervals across our North Louisiana Acreage. Furthermore, we also believe that we may add horizontal drilling locations across our entire acreage position through downspacing.

Significant operational control over our assets with low-cost operations. As the operator of a majority of our acreage, we have significant operational control over our assets. We seek to allocate capital among projects in a manner that optimizes both costs and returns, which we believe results in a highly efficient drilling program. We believe maintaining operational control will enable us to enhance returns by implementing more efficient and cost-effective operating practices, such as through the selection of economic drilling locations, the opportunistic timing of development and ongoing improvement of drilling, completion and operating techniques. Our contiguous acreage blocks, and our practice and history of exchanging and consolidating acreage with adjacent

 



 

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operators, allow us to increase our working interest in our wells and provide flexibility to adjust our drilling and completion techniques, such as pad drilling and the length of our horizontal laterals, in order to optimize our well results, drilling costs and returns.

Balanced asset portfolio with significant capital allocation optionality. We believe our balanced exposure to both oil and natural gas gives us the ability to adjust our capital plan and drilling program to rebalance our production as market conditions evolve. We have significant exposure to natural gas and NGLs in our North Louisiana Acreage and significant exposure to oil, natural gas and NGLs in our Eagle Ford Acreage. As of June 30, 2016, 53% and 47% of our total proved reserves were comprised of liquids and natural gas, respectively. In addition, 52% and 48% of our production for the nine months ended September 30, 2016 on a pro forma basis was comprised of liquids and natural gas, respectively. As changes in the commodity price environment occur, we intend to adapt and manage our capital spending and production profile to benefit from these trends.

Management and technical teams with substantial technical and operational expertise. Our management and technical teams have significant industry experience and a long history of collaboration in the identification, execution and integration of acquisitions and in cost-efficient management of profitable, large-scale drilling programs. Additionally, we have substantial expertise in advanced drilling and completion technologies and decades of collective experience in operating in the Eagle Ford and North Louisiana. Mr. Graham, our Chief Executive Officer, and Mr. Bahr, our President, co-founded one of the predecessors to, and Mr. Graham served as Chief Executive Officer of, MRD, which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Further, our management team has a proven track record of returning value to shareholders and a significant economic interest in us directly and through its equity interests in each of WildHorse Holdings and Esquisto Holdings, as shown below in “Corporate Reorganization.” We believe our management team is motivated to use its experience in identifying and creating value across our acreage and drilling highly productive wells to deliver attractive returns, maintain safe and reliable operations and create shareholder value.

Geographically advantaged assets with significant midstream infrastructure to service our production. Our acreage position is in close proximity to end markets for oil, natural gas and NGLs, providing us with a regional price advantage. For example, low oil and natural gas basis differentials along the Gulf Coast represent a competitive advantage when compared to other plays, such as the Marcellus, Utica, Permian and DJ. Recently developed and low-cost legacy infrastructure is in place across significant portions of our acreage to support our development program. In addition, we own and operate a large portion of our necessary midstream infrastructure which provides us with improved netbacks. On our North Louisiana Acreage, we own and operate a gathering system with capacity of approximately 250 MMcf/d as of September 30, 2016, as well as a saltwater disposal system. On our Eagle Ford Acreage, we own substantial fresh water supply and storage and are in the process of developing a saltwater disposal system. Our midstream infrastructure allows us to realize lower operating costs and provides us with increased flexibility in our development program. In addition, while not currently contemplated, our midstream infrastructure could prove to be a future source of additional capital if monetized at an attractive valuation.

Recent Developments

Rosewood Acquisition

In September 2016, we agreed to acquire from certain third parties approximately 7,500 net acres, consisting primarily of additional working interests in our Eagle Ford Acreage in Lee County (the “Rosewood Acquisition”). The closing of the acquisition will occur contemporaneously with the closing of this offering, and we will issue 981,320 shares to such third parties as consideration (based on the midpoint of the price range set forth on the cover page of this prospectus). The actual number of shares to be issued to such sellers will be determined by dividing the acquisition consideration value of approximately $19.6 million by the price per share

 



 

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of our common stock in this offering. Accordingly, an increase or decrease in the initial public offering price will decrease or increase, as applicable, the number of shares to be issued to the sellers. For example, a $1.00 decrease in the assumed initial public offering price would result in the sellers receiving an additional 51,649 shares of our common stock. The acreage we will acquire includes one producing well that was producing approximately 30 Boe/d as of October 15, 2016 and results in the addition of approximately 78 net drilling locations to our drilling inventory.

Burleson North Acquisition

In October 2016, Acquisition Co. entered into a purchase and sale agreement with Clayton Williams Energy, Inc. to acquire approximately 158,000 net acres of oil and gas properties adjacent to our Eagle Ford Acreage (the “Burleson North Assets”) for a purchase price of $400.0 million in cash, subject to customary purchase price adjustments, $45.0 million of which was funded at signing by Acquisition Co. The Burleson North Assets produced an average of approximately 3.9 MBoe/d (80% oil) for the three months ended September 30, 2016 and added 670 gross and net drilling locations to our drilling inventory. We expect to close the Burleson North Acquisition prior to or contemporaneously with the closing of this offering, using a portion of the proceeds from this offering to fund the remaining purchase price.

November Acquisition

In November 2016, we acquired from certain third parties approximately 4,900 net acres in Burleson County for approximately $30.0 million (the “November Acquisition” and, together with the Burleson North Acquisition and the Rosewood Acquisition, the “Acquisitions”). The assets acquired in the November Acquisition were producing approximately 14 Boe/d as of October 1, 2016, and result in the addition of 68 gross (66 net) drilling locations to our drilling inventory.

Capital Program

We intend to develop our multi-year drilling inventory by utilizing our significant expertise in horizontal drilling to grow our production, reserves and cash flow. Our 2016 capital budget for drilling and completion, leasehold acquisition and midstream infrastructure development is $137.5 million, of which we have invested $99.8 million through September 30, 2016. We are currently running a one-rig program in our Eagle Ford Acreage and we intend to add one rig in our North Louisiana Acreage in late 2016. We intend to add four additional drilling rigs during 2017 in order to a run a six-rig program by the end of 2017 with four rigs drilling in our Eagle Ford Acreage and two rigs drilling in our North Louisiana Acreage. For the twelve months ending December 31, 2017, we plan to invest $539.5 million in capital expenditures as follows:

 

   

$471.2 million to drill and complete 81 gross (67 net) wells across our acreage as follows:

 

  ¡    

$409.0 million in our Eagle Ford Acreage to drill 84 gross (73 net) wells with an average lateral length of 6,406 feet, 72 gross (62 net) of which we expect to complete in 2017;

 

  ¡    

$62.2 million in our North Louisiana Acreage to drill 12 gross (seven net) wells with an average lateral length of 9,062 feet, nine gross (five net) of which we expect to complete in 2017;

 

   

$39.6 million for lease extension and renewals;

 

   

$22.3 million for midstream infrastructure development; and

 

   

$6.4 million in other investments, including seismic and capital workover projects.

We plan to fund our 2017 capital program through cash flow from operations and borrowings under our new $1.0 billion revolving credit facility. Further, we intend to monitor conditions in the debt capital markets and may determine to issue long-term debt securities, including potentially in the near term, to fund a portion of our 2017 capital program. We cannot predict with certainty the timing, amount and terms of any future issuances of any such debt securities.

 



 

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By operating the majority of our acreage, the amount and timing of our capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including the success of our drilling activities, volatility in commodity prices, the availability of necessary equipment, infrastructure, personnel and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and acquisition costs. Any reduction in our capital expenditure budget could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity. For further discussion of the risks we face, please read “Risk Factors—Risks Related to Our Business—Our development projects and acquisitions 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.”

Risk Factors

An investment in our common stock involves a number of risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. You should carefully consider, in addition to the other information contained in this prospectus, the risks described in “Risk Factors” before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

 

   

Oil, natural gas and NGL prices are volatile. A 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 development projects and acquisitions 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.

 

   

Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

 

   

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.

 

   

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.

 

   

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.

 

   

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 or the leases are renewed.

 

   

Our producing properties are located in the Eagle Ford and in North Louisiana, making us vulnerable to risks associated with operating in a limited number of geographic areas.

 

   

Certain factors could require us to write-down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

 

   

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

 



 

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NGP has the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.

 

   

NGP and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable NGP to benefit from corporate opportunities that might otherwise be available to us.

 

   

We expect to be a “controlled company” and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements.

Corporate Reorganization

We were incorporated under the laws of the State of Delaware in August 2016 to become a holding company for the assets and operations of WildHorse and Esquisto. WildHorse was founded in June 2013, with equity commitments from affiliates of NGP and its Management Members, and Esquisto was founded in June 2014.

Contemporaneously with this offering, (i) the current owners of WildHorse will exchange all of their interests in WildHorse for equivalent interests in WildHorse Investment Holdings and the current owners of Esquisto will exchange all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings will contribute all of the interests in WildHorse to WildHorse Holdings, Esquisto Investment Holdings will contribute all of the interests in Esquisto to Esquisto Holdings and the current owner of Acquisition Co. will contribute all of its interests in Acquisition Co. to Acquisition Co. Holdings, (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will issue management incentive units to certain of our officers and employees as described in this prospectus and (iv) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will contribute all of the interests in WildHorse, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WildHorse, Esquisto and Acquisition Co. will become direct, wholly owned subsidiaries of WildHorse Resource Development Corporation.

We were incorporated to serve as the issuer in this offering and have no previous operations, assets or liabilities. For more information on our reorganization and the ownership of our common stock by our principal stockholders, please see “Security Ownership of Certain Beneficial Owners and Management” and the unaudited pro forma financial statements included elsewhere in this prospectus.

 



 

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The following diagram indicates our simplified ownership structure after giving effect to our Corporate Reorganization and this offering (assuming that the underwriters’ option to purchase additional shares is not exercised) and does not give effect to 9,512,500 shares of common stock reserved for future issuance under the WildHorse Resource Development Corporation 2016 Long-Term Incentive Plan (our “LTIP”), as described in “Executive Compensation—2016 Long-Term Incentive Plan” or our intended grant of 265,000 restricted shares of common stock to certain officers and directors under such plan in connection with the successful completion of this offering. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses” for more information.

 

 

LOGO

 

* Includes shares issued in connection with the Rosewood Acquisition.

Our Principal Stockholders

Following the completion of this offering and our Corporate Reorganization, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will directly own 23.3%, 42.6% and 2.8%, respectively, of our common stock, or 22.3%, 40.7% and 2.7%, respectively, if the underwriters’ option to purchase additional shares is exercised in full. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings are controlled by NGP. Please see “—Corporate Reorganization.”

 



 

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Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we will not be required to:

 

   

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

 

   

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations;

 

   

comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and our financial statements;

 

   

provide certain disclosures regarding executive compensation required of larger public companies or hold stockholder advisory votes on the executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or

 

   

obtain stockholder approval of any golden parachute payments not previously approved.

We will cease to be an emerging growth company upon the earliest of:

 

   

the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

 

   

the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

 

   

the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

 

   

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act 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, as amended (the “Securities Act”), for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 9805 Katy Freeway, Suite 400, Houston, Texas 77024, and our telephone number at that address is (713) 568-4910.

Our website address is www.wildhorserd.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (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, or otherwise accessible through, 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

WildHorse Resource Development Corporation.

 

Common stock offered by us

27,500,000 shares (or 31,625,000 shares, if the underwriters exercise in full their option to purchase additional shares).

 

Common stock outstanding after this offering

91,000,000 shares (or 95,125,000 shares, if the underwriters exercise in full their option to purchase additional shares).

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to 4,125,000 additional shares of our common stock to the extent the underwriters sell more than 27,500,000 shares of common stock in this offering.

 

Use of proceeds

We expect to receive approximately $513.7 million of net proceeds, based upon the assumed initial public offering price of $20.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $26.0 million.

 

  We intend to use the proceeds from this offering, along with borrowings under our new revolving credit facility, to (i) fund the remaining portion of the Burleson North Acquisition purchase price and (ii) repay in full and terminate the WildHorse revolving credit facility and the Esquisto revolving credit facility and repay in full all notes payable by Esquisto to its members. Please read “Use of Proceeds.”

 

Conflicts of Interest

Because an affiliate of each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. is a lender under the WildHorse revolving credit facility and/or the Esquisto revolving credit and will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under such credit facilities, each of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and Comerica Securities, Inc. is deemed to have a conflict of interest within the meaning of Rule 5121 of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering will be conducted in accordance with Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Barclays Capital Inc. has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, specifically including those inherent in Section 11 thereof. Barclays Capital Inc. will not receive any additional fees for

 



 

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serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Barclays Capital Inc. against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. See “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

 

Dividend policy

We do not anticipate paying any cash dividends on our common stock. In addition, our new revolving credit facility places certain restrictions on our ability to pay cash dividends. Please read “Dividend Policy.”

 

Listing and trading symbol

We have been approved to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “WRD.”

 

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 common stock.

The information above excludes 9,512,500 shares of common stock reserved for issuance pursuant to our LTIP, which we intend to adopt in connection with the completion of this offering and does not include 265,000 restricted shares of our common stock expected to be issued to certain officers and directors in connection with the successful completion of this offering pursuant to our LTIP. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses” for more information.

 



 

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Summary Pro Forma Financial Data

The following table shows summary unaudited pro forma financial data of WildHorse Development for the periods and as of the dates indicated.

The summary unaudited pro forma statement of operations data for the year ended December 31, 2014 has been prepared to give pro forma effect to (i) the Corporate Reorganization and (ii) the contribution of the Initial Esquisto Assets to Esquisto as part of its formation as if they had occurred on January 1, 2014. The summary unaudited pro forma statements of operations data for the year ended December 31, 2015 and the nine months ended September 30, 2015 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The summary unaudited statement of operations data for the nine months ended September 30, 2016 and the summary unaudited pro forma balance sheet data as of September 30, 2016 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015 and September 30, 2016, respectively. Please see “Use of Proceeds.” This data is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

For selected historical consolidated financial data of WildHorse, our predecessor, as of and for the years ended December 31, 2014 and 2015, derived from the audited historical consolidated financial statements of WildHorse, please see “Selected Historical Consolidated and Unaudited Pro Forma Financial Data” included elsewhere in this prospectus.

 



 

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You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “—Corporate Reorganization,” the historical consolidated financial statements of WildHorse and the unaudited pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

 

     Pro Forma  
     Year Ended December 31,     Nine Months Ended
September 30,
 
           2014                 2015           2015     2016  
     (Unaudited)  
     (In thousands, except per share data)  

Statement of Operations Data:

        

Revenues:

        

Oil sales

   $ 17,826      $ 142,614      $ 112,087      $ 86,279   

Natural gas sales

     38,345        38,063        29,199        29,560   

NGL sales

     2,285        6,722        5,069        4,428   

Gathering system income

     —          314        —          1,158   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     58,456        187,714        146,355        121,425   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

        

Lease operating expenses

     10,540        35,339        26,272        21,865   

Gathering system operating expense

     —          914        317        99   

Production and ad valorem taxes

     3,405        12,991        9,915        8,600   

Cost of oil sales

     687        —          —          —     

Depreciation, depletion and amortization

     23,269        99,009        71,834        79,519   

Impairment of proved oil and gas properties

     24,721        9,312        8,032        —     

General and administrative expenses

     8,226        16,611        11,707        14,058   

Exploration expenses

     1,599        17,863        14,512        8,975   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     72,447        192,039        142,589        133,116   
  

 

 

   

 

 

   

 

 

   

 

 

 

Gain (loss) from operations

     (13,991     (4,326     3,766        (11,691
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense):

        

Interest expense

     (3,286     (4,185     (3,135     (3,135

Other expense

     (120     (150     (472     (429

Gain (loss) on derivatives instruments

     6,514        13,854        7,179        (8,694
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income

     3,108        9,519        3,572        (12,258
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) before income taxes

     (10,883     5,193        7,338        (23,949

Income tax benefit (expense)

     4,502        (832     (1,759     9,595   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income

   $ (6,381   $ 4,361      $ 5,579      $ (14,354
  

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income per common share:

        

Basic and diluted

   $ (0.07   $ 0.05      $ 0.06      $ (0.16

Weighted average common shares outstanding:

        

Basic and diluted

     91,000        91,000        91,000        91,000   

Other Financial Data:

        

Adjusted EBITDAX(1)

   $ 32,120      $ 132,906      $ 104,381      $ 81,726   

Balance Sheet Data (at period end):

        

Cash and cash equivalents

         $ 526   

Total assets

         $ 1,322,390   

Total liabilities

         $ 276,200   

Owners’ equity

         $ 1,046,190   

Total liabilities and owners’ equity

         $ 1,322,390   

 

(1) Adjusted EBITDAX is not a financial measure calculated in accordance with United States generally accepted accounting principles (“GAAP”). For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure.”

 



 

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Non-GAAP Financial Measure

Adjusted EBITDAX is a supplemental non-GAAP financial performance 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 (loss) income before interest expense, income taxes, depreciation, depletion and amortization, exploration expense and impairment of unproved properties, gains on derivatives excluding effects of settled derivatives and other non-cash and non-recurring operating items. Adjusted EBITDAX is not a measure of net (loss) income as determined according to GAAP.

Management believes Adjusted EBITDAX is a useful performance measure because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net (loss) 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 (loss) income as determined in accordance with GAAP. 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 our 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 a reconciliation of Adjusted EBITDAX to net (loss) income, our most directly comparable financial measure calculated and presented in accordance with GAAP.

 

     Pro Forma  
     Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2014     2015     2015     2016  
     (In thousands)  

Adjusted EBITDAX reconciliation to net (loss) income:

        

Net (loss) income

   $ (6,381   $ 4,361      $ 5,579      $ (14,354

Interest expense

     3,286        4,185        3,135        3,135   

Income tax (benefit) expense

     (4,502     832        1,759        (9,595

Depreciation, depletion and amortization

     23,269        99,009        71,834        79,519   

Exploration expense and impairment of properties

     26,320        27,175        22,544        8,975   

(Gain) loss on derivatives

     (6,514     (13,854     (7,179     8,694   

Effects of derivative settlements

     (2,712     11,958        7,324        5,637   

Non-cash liability amortization

     (646     (759     (615     (286
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 32,120      $ 132,906      $ 104,381      $ 81,726   
  

 

 

   

 

 

   

 

 

   

 

 

 

 



 

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Summary Combined Reserve and Pro Forma Operating Data

Summary Reserve Data

The following table summarizes the estimated net proved, probable and possible oil, natural gas and NGL reserves of WildHorse and Esquisto on a combined basis as of June 30, 2016 without giving effect to any of the Acquisitions. Cawley prepared Esquisto’s reserves estimates and audited WildHorse’s reserves estimates. Such reserves estimates were prepared in accordance with the SEC’s rules regarding oil, natural gas and NGL reserve reporting.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business—Reserve Data” in evaluating the material presented below.

 

     As of
June 30,
2016(1)
 

Estimated Proved Reserves:

  

Oil (MMBbls)

     49.7   

Natural gas (Bcf)

     300.8   

NGLs (MMBbls)

     7.6   
  

 

 

 

Total proved reserves (MMBoe)

     107.4   
  

 

 

 

Estimated Proved Developed Reserves:

  

Oil (MMBbls)

     9.3   

Natural gas (Bcf)

     142.0   

NGLs (MMBbls)

     2.6   
  

 

 

 

Total proved developed reserves (MMBoe)

     35.6   
  

 

 

 

Proved developed reserves as a percentage of total proved reserves

     33.1

Estimated Proved Undeveloped Reserves:

  

Oil (MMBbls)

     40.4   

Natural gas (Bcf)

     158.7   

NGLs (MMBbls)

     5.0   
  

 

 

 

Total proved undeveloped reserves (MMBoe)

     71.8   
  

 

 

 

Proved undeveloped reserves as a percentage of total proved reserves

     66.9

Estimated Probable Reserves:

  

Oil (MMBbls)

     61.3   

Natural gas (Bcf)

     191.4   

NGLs (MMBbls)

     7.4   
  

 

 

 

Total probable reserves (MMBoe)(2)

     100.6   
  

 

 

 

Estimated Possible Reserves:

  

Oil (MMBbls)

     109.9   

Natural gas (Bcf)

     1,109.8   

NGLs (MMBbls)

     12.9   
  

 

 

 

Total possible reserves (MMBoe)(2)

     307.8   
  

 

 

 

 

(1)

WildHorse’s and Esquisto’s estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC rules. For oil and NGL volumes, the average WTI posted price of $43.12 per barrel as of June 30, 2016 was adjusted for

 



 

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  quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.24 per MMBtu as of June 30, 2016 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the WildHorse properties are $39.78 per barrel of oil, $2.32 per Mcf of natural gas and $12.37 per barrel of NGL as of June 30, 2016. The average adjusted product prices weighted by production over the remaining lives of the Esquisto properties are $40.46 per barrel of oil, $1.35 per Mcf of natural gas and $10.35 per barrel of NGL as of June 30, 2016.
(2) All of our estimated probable and possible reserves are classified as undeveloped.

Production and Operating Data

The following table sets forth information regarding our pro forma production, realized prices and production costs for the nine months ended September 30, 2016 and the year ended December 31, 2015. For additional information on pro forma adjustments and price calculations, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     Year Ended
December 31, 2015
     Nine Months
Ended
September 30, 2016
 

Net Production Volumes:

     

Oil (MBbls)

     3,100.9         2,246.9   

Natural gas (MMcf)

     16,766.7         14,766.3   

NGLs (MBbls)

     564.1         407.0   
  

 

 

    

 

 

 

Total (MBoe)

     6,459.5         5,114.9   
  

 

 

    

 

 

 

Average net daily production (MBoe/d)

     17.7         18.7   

Average Sales Prices:

     

Oil (per Bbl) (excluding impact of settled derivatives)

   $ 45.99       $ 38.40   

Oil (per Bbl) (after impact of settled derivatives)

   $ 46.32       $ 39.28   

Natural gas (per Mcf) (excluding impact of settled derivatives)

   $ 2.27       $ 2.00   

Natural gas (per Mcf) (after impact of settled derivatives)

   $ 2.92       $ 2.25   

NGLs (per Bbl)

   $ 11.92       $ 10.88   
  

 

 

    

 

 

 

Total (per Boe) (excluding impact of settled derivatives)

   $ 29.01       $ 23.51   

Total (per Boe) (after impact of settled derivatives)

   $ 30.86       $ 24.62   
  

 

 

    

 

 

 

Expenses per Boe:

     

Lease operating expenses

   $ 5.47       $ 4.27   

Gathering system operating expenses

   $ 0.14       $ 0.02   

Production and ad valorem taxes

   $ 2.01       $ 1.68   

Depreciation, depletion and amortization

   $ 15.33       $ 15.55   

Impairment of proved oil and gas properties

   $ 1.44         —     

General and administrative expenses

   $ 2.57       $ 2.75   

Exploration expenses

   $ 2.77       $ 1.75   

 



 

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RISK FACTORS

An investment in our common stock involves a number of risks. You should carefully consider each of the following risk factors and all of the other information set forth in this prospectus before making an investment decision. If any of the events discussed in the risk factors below actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. If any of these risks occur, the trading price of our common stock could decline and you may lose all or part of your investment.

Risks Related to Our Business

Oil, natural gas and NGL prices are volatile. A 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.

The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and the carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through November 7, 2016, the WTI spot price for oil declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

 

   

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, its members and other state-controlled oil companies relating to oil price and production controls;

 

   

the level of global exploration, development and production;

 

   

the level of global inventories;

 

   

prevailing prices on local price indexes in the areas 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 and natural disasters;

 

   

technological advances affecting energy consumption;

 

   

the price and availability of alternative fuels;

 

   

expectations about future commodity prices; and

 

   

U.S. federal, state and local and non-U.S. governmental regulation and taxes.

 

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In the second half of 2014, oil prices began a rapid and significant decline from a high WTI spot price of $107.95 on June 20, 2014, as global oil supply began to outpace demand. Prices continued to decline through 2015 and into 2016, reaching a low of $26.19 on February 11, 2016. Since then, prices have recovered some with oil prices reaching a high of $51.23 in the second quarter of 2016, although oil prices have subsequently fallen to $44.89 as of November 7, 2016. In general, the imbalance between supply and demand, and the perception of such imbalance, that has influenced the current commodity price cycle reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of a sustained effort to retain and capture additional 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. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and excess storage levels begin to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure on oil prices. NGL prices generally correlate with the price of oil. Additionally, the supply of NGLs has continued to grow in the United States due to an increase in industry participants targeting NGL producing projects, which places additional pressure on the price of NGLs. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and thus far in 2016.

Similarly, the declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price decline cannot be accurately predicted. Compared to 2014, our pro forma realized oil price for 2015 fell 47% to $45.99 per barrel, and our pro forma realized oil price for the nine months ended September 30, 2016 has further decreased to $38.40 per barrel. Similarly, our pro forma realized natural gas price for 2015 decreased 43% to $2.27 per Mcf, and our pro forma realized price for NGLs declined 53% to $11.92 per barrel. For the nine months ended September 30, 2016, our pro forma realized price for natural gas was $2.00 per Mcf, and our realized price for NGLs was $10.88 per barrel.

Lower commodity prices may reduce our cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub strip prices may adversely affect our drilling economics and our ability to raise capital, which may require us to re-evaluate and postpone or eliminate our development program, and result in the reduction of some of our proved undeveloped reserves and related standardized measure. 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 and ability to finance planned capital expenditures.

Our development projects and acquisitions 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 and expect to continue to make substantial capital expenditures related to our development projects and acquisitions. Our 2016 and 2017 capital budget is $137.5 million and $539.5 million, respectively. We expect to fund our 2016 and 2017 capital budget with cash generated by operations and borrowings under our new revolving credit facility. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, 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 our other stockholders. The actual amount and timing

 

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of our future capital expenditures may differ materially from our estimates as a result of, among other things: commodity prices; actual drilling results; the availability 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 amount of hydrocarbons we are able to produce from existing wells;

 

   

our ability to acquire, locate and produce new reserves;

 

   

the amount of our operating expenses;

 

   

cash settlements from our derivative activities;

 

   

our ability to borrow under our new revolving credit facility; and

 

   

our ability to access the capital markets.

If our revenues or the borrowing base under our new revolving credit facility 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 our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. For a period of 180 days following the date of this prospectus, we will not be able to sell any shares of our common stock, whether pursuant to a private or public offering, without the prior written consent of Barclays Capital Inc. See “Underwriting (Conflicts of Interest)” for more information. If cash flow generated by our operations or available borrowings under our new revolving credit facility 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.

Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. The difficulties we face drilling horizontal wells include:

 

   

landing our wellbore in the desired drilling zone;

 

   

staying in the desired drilling zone while drilling horizontally through the formation;

 

   

running our casing the entire length of the wellbore; and

 

   

being able to run tools and other equipment consistently through the horizontal wellbore.

Difficulties that we face while completing our wells include the following:

 

   

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 drilling in new or emerging formations are more

 

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uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and 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 we anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

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, production and acquisition 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, 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.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including:

 

   

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

 

   

issues related to compliance with environmental regulations;

 

   

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 on acceptable terms;

 

   

title issues; and

 

   

other market limitations in our industry.

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 new revolving credit facility, 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 flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

 

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If our cash flow 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 indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness may be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing or 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 new revolving credit facility restricts our ability to dispose of assets and imposes limitations on our use of proceeds from dispositions. 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 existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our new revolving credit facility contains a number of significant covenants, including restrictive covenants that will limit our ability to, among other things:

 

   

incur additional indebtedness;

 

   

make loans to others;

 

   

make investments;

 

   

merge or consolidate with another entity;

 

   

make certain payments;

 

   

hedge future production or interest rates;

 

   

incur liens;

 

   

sell assets; and

 

   

engage in certain other transactions without the prior consent of the lenders.

In addition, our new revolving credit facility requires us to maintain compliance with certain financial covenants.

The restrictions in our new revolving credit facility will also impact our ability to obtain capital to withstand a 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 new revolving credit facility may impose on us.

A breach of any covenant in our new revolving credit facility will result in a default under the agreement and an event of default under the agreement if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under our new revolving credit facility and in an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would 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.

Any significant reduction in our borrowing base under our new revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our new revolving credit facility, which we plan to enter into in connection with the completion of this offering, will limit the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole

 

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discretion, will unilaterally determine based upon projected revenues from our oil, natural gas and NGL properties and our commodity derivative contracts. Such determinations will be made on a regular basis semi-annually (each a “Scheduled Redetermination”), at our option in connection with a material acquisition, at our option no more than twice in any fiscal year and at the option of lenders (the “Required Lenders”) with more than 66.6% of the loans and commitments under the facility no more than twice in any fiscal year (each such redetermination other than a Scheduled Redetermination, an “Interim Redetermination” and any Scheduled Redetermination or Interim Redetermination, a “Redetermination”). In connection with a Redetermination, any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments, and maintaining or any decrease in the borrowing base requires the consent of the Required Lenders. The borrowing base will also automatically decrease upon the issuance of certain debt, the sale or other disposition of certain assets and the early termination of certain swap agreements. We expect our initial borrowing base to be $450.0 million, following the completion of the Burleson North Acquisition. Our next Scheduled Redetermination is expected in April 2017.

In the future, we may not be able to access adequate funding under our new revolving credit facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a 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 a defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base 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 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.

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

We enter into derivative instrument contracts for a portion of our oil and natural gas production. As of November 1, 2016, we had entered into swaps and collars through December 2019 covering a total of 1,664 MBbl of our projected oil production and 17,520,000 MMBtu of our projected natural gas production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

 

   

production is less than the volume covered by the derivative instruments;

 

   

the counterparty to the derivative instrument defaults on its contractual obligations;

 

   

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

   

there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse 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 our counterparties, oil, natural gas and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs or from reductions in interest rates, which could have a material adverse effect on our financial condition. In addition, our new revolving credit facility limits our ability to enter into commodity hedges covering greater than 100% of our reasonably anticipated projected proved production for the first two years of the facility and 75% of reasonably anticipated projected proved production for the following three years.

 

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Our 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 do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices or, to the extent we have interest rate derivative instrument contracts, increasing interest rates, our derivative contract receivable positions would generally increase, which increases 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 derivative contracts.

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, natural gas and NGL 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 we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates of proved, probable and possible reserves 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. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped, probable and possible reserves will be developed within the periods anticipated.

You should not assume that the present value of future net revenues from our reserves presented in this prospectus is the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of June 30, 2016 and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $43.12 per barrel of oil (WTI) and $2.24 per MMBtu of natural gas (Henry Hub spot), which, for certain periods in 2016, 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.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with

 

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industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future in connection with the Acquisitions or otherwise may not produce as expected. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

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 and could be liable for certain financial obligations of the operators or any of our contractors to the extent such operator or contractor is unable to satisfy such obligations.

We have identified 4,391 potential drilling locations. We do not expect to operate 1,880 of such locations, and there is no assurance that we will operate all of our other drilling locations. In addition, unless we are successful in increasing our working interest in our other drilling locations through acreage exchanges and consolidation efforts, we will not be the operator with respect to these other identified horizontal drilling locations. We have limited ability to exercise influence over the operations of the drilling locations operated by our partners, and there is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners 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 drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

Further, we may be liable for certain financial obligations of the operator of a well in which we own a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, we may be liable for certain obligations of our contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material adverse effect on our financial condition.

Our identified 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 substantial amount of capital that would be necessary to drill such locations.

Our management and technical teams 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, the cooperation of other working interest owners and other factors. Because of

 

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these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil 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 September 30, 2016, we had identified 2,977 gross horizontal drilling locations on our Eagle Ford Acreage and 1,414 gross horizontal drilling locations on our North Louisiana Acreage. As a result of the limitations described in this prospectus, we may be unable to drill many of our identified locations. 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 projects and acquisitions 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, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which could have a material adverse effect on the borrowing base under our new revolving credit facility or 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 and may be required to reduce our estimated proved reserves, which could reduce the borrowing base under our new revolving credit facility.

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 or the leases are renewed.

As of September 30, 2016, approximately 46% of our total net acreage was held by production. 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 or the leases are renewed. For example, as of September 30, 2016, 9% and 32% of our net undeveloped acreage will expire in 2016 and 2017, respectively, after giving effect to the Rosewood Acquisition. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we intend to extend substantially all of our net acreage associated with identified drilling locations through a combination of development drilling, the payment of pre-agreed leasehold extension and renewal payments pursuant to an option to extend or the negotiation of lease extensions, we may not be successful in extending our leases. Additionally, where we do not have options to extend a lease, we may not be successful in negotiating extensions or renewals or any payments related to such extensions or renewals may be more than anticipated. Please see “Business—Reserve Data—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for extending and renewing our acreage. Our ability to drill and develop our acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL 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.

Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.

 

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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 oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in our areas of operation 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.

Our producing properties are located in the Eagle Ford and in North Louisiana, making us vulnerable to risks associated with operating in a limited number of geographic areas.

All of our producing properties are geographically concentrated in the Eagle Ford and in North Louisiana. At June 30, 2016, all of our total estimated proved reserves were attributable to properties located in these areas. 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 these areas 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.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do 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 transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a transportation facility. Our natural gas production is generally transported by our or third-party gathering lines from the wellhead to a gas processing facility or transmission pipeline. We do not control these trucks and other third-party transportation facilities and our access to them 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 our or 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. Any such shut-in or curtailment, 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.

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

The development of our estimated PUDs, probable and possible reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs, probable and possible reserves may not be ultimately developed or produced.

As of June 30, 2016, 67% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Moreover, the development of our probable and possible reserves will

 

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require additional capital expenditures and are less certain to be recovered than proved reserves. Estimated future development costs relating to the development of our PUDs at June 30, 2016 are approximately $675.0 million over the next five years. We expect to fund these expenditures through cash generated by operations, borrowings under our new revolving credit facility and other sources of capital. Our ability to fund these expenditures is subject to a number of risks. See “—Our development projects and acquisitions 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.” Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and our probable and possible reserves and future net 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. Furthermore, there is no certainty that we will be able to convert our PUDs to developed reserves or our probable and possible reserves into proved reserves or that our undeveloped or unproved reserves will be economically viable or technically feasible to produce.

Further, SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. As a result, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

Certain factors could require us to write-down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Accounting rules require that we periodically review 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 impairment charge to earnings. Recently, commodity prices have declined significantly. On November 7, 2016, the WTI spot price for crude oil was $44.89 per barrel and the Henry Hub spot price for natural gas was $2.816 per MMBtu, representing decreases of 58% and 65%, respectively, from the high of $107.95 per barrel of oil and $8.15 per MMBtu for natural gas during 2014. Likewise, NGLs have suffered significant recent declines in realized prices. 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. As a result of lower commodity prices, we recorded $24.7 million and $9.3 million of impairment expense during the years ended December 31, 2014 and 2015, respectively, on a pro forma basis. We could experience further material write-downs as a result of lower commodity prices or other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

Unless we replace our reserves with new reserves and develop those new 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 our 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.

 

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

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

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

We normally sell our production to a relatively small number of customers, as is customary in our business. For the years ended December 31, 2015 and 2014, three and two purchasers, respectively, accounted for an aggregate 70% and 67%, respectively, of WildHorse’s and Esquisto’s total revenue on a combined basis. During such years, no other purchaser accounted for 10% or more of WildHorse’s and Esquisto’s revenue on a combined basis. The loss of any such greater than 10% purchaser as a purchaser could 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, health and safety aspects of our operations or otherwise relating to environmental protection. 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 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; and 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 often involve taking 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. 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 liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us 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 certain instances, citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws, or to challenge our ability to receive environmental permits that we need to operate. 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. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.

 

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To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and 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 our 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 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, air and shoreline contamination;

 

   

abnormally pressured formations;

 

   

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

   

fires, explosions and ruptures of pipelines;

 

   

personal injuries and death;

 

   

natural disasters; and

 

   

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

Any of these events 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;

 

   

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, 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.

Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

WildHorse and Esquisto were formed in 2013 and 2014, respectively. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

In addition, we have grown rapidly over the last several years. Our management believes 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. Prior to this offering, WildHorse and Esquisto had separate management teams, and going forward, after giving effect to the Corporate Reorganization, we will have one management team. Further, the transition services agreement we will enter into in connection with the closing of this offering will only be effective for six months. Additionally, the following factors could present difficulties:

 

   

increased responsibilities for our executive level personnel;

 

   

increased administrative burden;

 

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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 incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling 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 in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

   

unexpected drilling conditions;

 

   

title issues;

 

   

pressure or lost circulation in formations;

 

   

equipment failures or accidents;

 

   

adverse weather conditions;

 

   

compliance with environmental and other governmental or contractual requirements; and

 

   

increases in the cost of, and 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 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 completed acquisitions, including the Acquisitions, will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our 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.

In addition, our new revolving credit facility will impose certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit our ability to acquire assets and businesses.

 

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

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions 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 we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.

The unavailability or high cost of 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.

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, natural gas and NGL prices, causing periodic shortages of supplies and needed personnel. Our operations are concentrated in areas in which oilfield activity levels had 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, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services subsided due to reduced activity. To the extent that commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase and we could encounter delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to resume or increase our development activities, which 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 natural 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. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC, as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such

 

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facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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 to reduce GHG emissions from various sources. For example, the EPA requires certain large stationary sources to obtain preconstruction and operating permits for 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. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. 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. In May 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 sector, including production, processing, transmission and storage activities. Compliance will require enhanced record-keeping practices, the purchase of new equipment and could result in the increased frequency of maintenance and repair activities to address emissions leakage at well sites and compressor stations, and also may require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. The EPA has also announced that it intends to impose methane emission standards for existing sources but, to date, has not yet issued a proposal. And in 2015, EPA published a rule, known as the Clean Power Plan, to limit greenhouse gases from electric power plants. On February 9, 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. Depending on the ultimate outcome of those challenges, and how various states choose to implement this rule, it may alter the power generation mix between natural gas, coal, oil, and alternative energy sources, which would ultimately affect the demand for natural gas and oil in electric generation.

 

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While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement is expected to enter into force in November 2016. The United States is one of over 70 nations that has indicated it intends to comply with the agreement.

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.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have 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. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but certain federal agencies have asserted regulatory authority over certain aspects of the process. For example, 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 an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. The EPA also finalized rules in 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews are either underway or have been conducted that focus on environmental aspects of hydraulic fracturing practices. For example, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report preliminarily concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a

 

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public comment period and a formal review by the EPA’s Science Advisory Board, which is in progress. Other governmental agencies, including the White House Council on Environmental Quality, United States Department of Energy and the United States Department of the Interior, have or are currently evaluating various other aspects of hydraulic fracturing. These studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

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 also includes new 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. The well integrity rule took effect in January 2014. 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 saltwater gathered from such activities, which could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between the hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, 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. For example, in 2015, the United States Geological Study 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, most recently 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 in the permitting of saltwater disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

We dispose of large volumes of saltwater gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which 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 regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of saltwater gathered from our drilling and production activities by limiting volumes, disposal rates, 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.

 

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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 for acquisitions 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 greater financial, technical and personnel resources than we do. 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 has historically continually increased due to competition and 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 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. The 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.

Increases in interest rates could adversely affect our business.

We require continued access to capital and 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. We expect to use our new revolving credit facility to finance a portion of our future growth, and 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. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction, transportation and sales.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This

 

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fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

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

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we currently qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan

 

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for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated oil and natural gas reserves.

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires historical twelve month pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. In addition, WildHorse and Esquisto were generally not subject to U.S. federal, state or local income taxes other than certain state franchise taxes and federal income tax on one of our predecessor’s subsidiaries which has elected to be treated as a corporation for U.S. federal income tax purposes. Accordingly, our standardized measure does not provide for U.S. federal, state or local income taxes other than certain state franchise taxes and federal income tax for our predecessor subsidiary discussed above. However, following the Corporate Reorganization, we will be subject to U.S. federal, state and local income taxes. As a result, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our proved reserves.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancement and the introduction of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

Risks Related to this Offering and Our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

 

   

institute a more comprehensive compliance function;

 

   

comply with stock exchange rules;

 

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continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

   

establish new internal policies, such as those relating to insider trading; and

 

   

involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act for our fiscal year ending December 31, 2017, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2022. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated among us and the representatives of the underwriters, based on numerous factors, which we discuss in “Underwriting (Conflicts of Interest),” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

 

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The following factors could affect our stock price:

 

   

our operating and financial performance and drilling locations, including reserve estimates;

 

   

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

   

the public reaction to our press releases, our other public announcements and our filings with the SEC;

 

   

strategic actions by our competitors;

 

   

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

 

   

speculation in the press or investment community;

 

   

the failure of research analysts to cover our common stock;

 

   

sales of our common stock by us or other stockholders, or the perception that such sales may occur;

 

   

changes in accounting principles, policies, guidance, interpretations or standards;

 

   

additions or departures of key management personnel;

 

   

actions by our stockholders;

 

   

general market conditions, including fluctuations in commodity prices;

 

   

domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

   

the occurrence of any risks described under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

NGP has the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.

Upon completion of this offering, NGP, through WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, will beneficially own approximately 68.7% of our outstanding common stock (or approximately 65.7% if the underwriters’ over-allotment option is exercised in full). As a result, NGP will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of NGP with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Given this concentrated ownership, NGP would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of NGP. These directors’ duties as employees of NGP may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Furthermore, in connection with this offering, we expect to enter into a stockholders’ agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The stockholders’ agreement is expected to provide WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings with the right to designate a certain number of nominees to our board of directors so long as they and their affiliates collectively beneficially own more than 5% of the outstanding shares of our common stock. See “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” The existence of a significant stockholder and the stockholders’

 

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agreement may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, NGP’s concentration of stock ownership may adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. For example, three of our directors (Messrs. Gieselman, Hayes and Weber) are Partners or Managing Partners of NGP, which is in the business of investing in oil and natural gas companies with independent management teams that seek to acquire oil and natural gas properties, and Mr. Brannon is President of certain NGP portfolio companies. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”

NGP and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable NGP to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents will provide that NGP and its affiliates (including portfolio investments of NGP and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:

 

   

permit NGP and its affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

   

provide that if NGP or any of its affiliates, or any employee, partner, member, manager, officer or director of NGP or its affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Currently, NGP has multiple portfolio companies operating in the oil and natural gas industry, some of which may compete with us directly, including one company which operates in the broader Eagle Ford. Further, NGP or its affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability or option to pursue such opportunity. Such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to be unavailable to, or more expensive for, us to pursue. In this regard, we do not expect to enter into any agreement or arrangement with NGP and its affiliates to apportion opportunities between us, on the one hand, and NGP and its affiliates, on the other hand. In addition, NGP and its affiliates may dispose of oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, our

 

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renouncing our interest and expectancy in any business opportunity that may be, from time to time, presented to NGP or its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read “Description of Capital Stock—Corporate Opportunity.”

NGP is an established participant in the oil and natural gas industry and has access to resources greater than ours, which may make it more difficult for us to compete with NGP and its affiliates for commercial activities and potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and NGP or its affiliates, on the other hand, will be resolved in our favor. As a result, competition from NGP and its affiliates could adversely impact our results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation will authorize our board of directors, without stockholder approval, to issue preferred stock in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, the terms of such stock could cause it to be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. These provisions include:

 

   

at any time after a group that includes WildHorse Investment Holdings, Esquisto Investment Holdings, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP and certain of NGP’s affiliates (collectively, the “Sponsor Group”) no longer collectively own or control the voting of more than 50% of our outstanding common stock:

 

   

dividing our board of directors into three classes of directors, with each class serving a staggered three-year term;

 

   

providing that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, subject to the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares);

 

   

permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights;

 

   

permitting special meetings of our stockholders to be called only by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors, whether or not there exist any vacancies in previously authorized directorships (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding shares entitled to vote); and

 

   

requiring the affirmative vote of the holders of at least 75% in voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause;”

 

   

prohibiting cumulative voting in the election of directors;

 

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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and

 

   

providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Investors in this offering will experience immediate and substantial dilution of $8.29 per share.

Based on an assumed initial public offering price of $20.00 per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $8.29 per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of September 30, 2016 after giving effect to this offering would be $11.71 per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

We do not intend to pay cash dividends on our common stock, and our new revolving credit facility places restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, our new revolving credit facility places restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our common stock in the public market, or the perception that such sales may occur, 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 common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have 91,000,000 outstanding shares of common stock. This number includes 27,500,000 shares that we are selling in

 

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this offering but excludes 4,125,000 shares that we may sell in this offering if the underwriters’ over-allotment option is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ over-allotment option, the Existing Owners will own 62,518,680 shares of our common stock, or approximately 65.7% of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. Each of the Existing Owners will be party to a registration rights agreement, which will require us to effect the registration of its shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering.

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 9,512,500 shares of our common stock issued or reserved for issuance under our LTIP. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 may be made available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our 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 underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, all of our directors and executive officers, and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our common stock for a period of 180 days following the date of this prospectus. Barclays Capital Inc., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. See “Underwriting (Conflicts of Interest)” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation will authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

We expect to be a “controlled company” and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements.

Upon completion of this offering, the Sponsor Group will beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we expect to qualify as a “controlled company” within the meaning of the NYSE corporate governance standards. Under these rules, a company of

 

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which more than 50% of the voting power for the election of directors is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain applicable corporate governance requirements, including the requirements that:

 

   

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

 

   

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

 

   

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

 

   

an annual performance evaluation of the nominating and corporate governance and compensation committees.

Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to such corporate governance requirements. See “Management.”

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

We expect that the trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

Forward-looking statements may include statements about:

 

   

our business strategy;

 

   

our estimated proved, probable and possible reserves;

 

   

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;

 

   

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

 

   

our plans, objectives, expectations and intentions contained in this prospectus that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Risk Factors” in this prospectus.

 

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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 program. 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 $513.7 million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the proceeds from this offering, along with borrowings under our new revolving credit facility, to (i) fund the remaining portion of the Burleson North Acquisition purchase price and (ii) repay in full and terminate the WildHorse revolving credit facility and the Esquisto revolving credit facility and repay in full all notes payable by Esquisto to its members.

Affiliates of certain of the underwriters are lenders under the Esquisto revolving credit facility and the WildHorse revolving credit facility and, as a result, will indirectly receive a portion of the proceeds of this offering.

The following table illustrates our anticipated use of the proceeds of this offering:

 

Sources of Funds (in millions)

         

Uses of Funds (in millions)

      

Gross proceeds from this offering

   $ 550.0      

Burleson North Acquisition

   $ 355.0   

New revolving credit facility

     118.8      

Repayment of WildHorse revolving credit facility

     112.0   
     

Repayment of Esquisto revolving credit facility

     155.0   
     

Repayment of Esquisto notes payable to members

     10.5   
     

Underwriting discounts, fees and certain other expenses

     36.3   
  

 

 

       

 

 

 

Total

   $ 668.8      

Total

   $ 668.8   
  

 

 

       

 

 

 

As of September 30, 2016, WildHorse had $108.5 million of outstanding borrowings under the WildHorse revolving credit facility. Since that date and prior to the consummation of this offering, WildHorse has borrowed or expects to borrow an additional $3.5 million, resulting in approximately $112.0 million of outstanding borrowings under its credit facility prior to the completion of this offering. The WildHorse revolving credit facility matures on August 8, 2018 and bears interest at a variable rate, which was 3.03% per annum at September 30, 2016. Borrowings under the WildHorse revolving credit facility were incurred primarily to fund WildHorse’s capital expenditures and leasehold acquisitions.

As of September 30, 2016, Esquisto had $125.0 million of outstanding borrowings under the Esquisto revolving credit facility. Since that date and prior to the consummation of this offering, Esquisto has borrowed or expects to borrow an additional $30.0 million, resulting in approximately $155.0 million of outstanding borrowings under its credit facility prior to the completion of this offering. The Esquisto revolving credit facility matures on July 22, 2020 and bears interest at a variable rate, which averaged 2.79% per annum at September 30, 2016. Borrowings under the Esquisto revolving credit facility were incurred primarily to fund Esquisto’s capital expenditures and leasehold acquisitions, including the Comstock Acquisition. As of September 30, 2016, Esquisto had $9.6 million in principal amount of notes payable to certain of its members. The Esquisto notes payable to members are payable to such members by December 31, 2022 and bear interest after a year at the Applicable Federal Rate compounded annually, paid at maturity. Borrowings from Esquisto’s members were incurred primarily to fund general and administrative expenses incurred on behalf of Esquisto.

Affiliates of certain of the underwriters are lenders under the WildHorse revolving credit facility and/or the Esquisto revolving credit facility and accordingly will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under such credit facilities. Accordingly, this offering is being made in compliance with FINRA Rule 5121. Please read “Underwriting (Conflicts of Interest).”

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $26.0 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase for any reason, we would use the additional net proceeds to reduce borrowings under our new revolving credit facility. If the proceeds decrease for any reason, then we would make additional borrowings under our new revolving credit facility.

 

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our new revolving credit facility places restrictions on our ability to pay cash dividends.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2016:

 

   

on an actual basis for WildHorse, our predecessor;

 

   

on an as adjusted basis to give effect to the Corporate Reorganization; and

 

   

on an as further adjusted basis to give effect, along with borrowings under our new revolving credit facility, to (i) the sale of shares of our common stock in this offering at an assumed initial public offering price of $20.00 per share (which is the midpoint of the range set forth on the cover of this prospectus), (ii) the issuance of 981,320 shares of our common stock in connection with the closing of the Rosewood Acquisition and (iii) the application of the net proceeds from this offering and such borrowings under our new revolving credit facility to (a) fund the remaining portion of the Burleson North Acquisition purchase price and (b) repay in full and terminate the WildHorse revolving credit facility and the Esquisto revolving credit facility and repay in full all notes payable by Esquisto to its members, as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements and related notes appearing elsewhere in this prospectus.

 

     As of September 30, 2016  
         Actual             As Adjusted             As further    
Adjusted(1)
 
     (In thousands, except number of shares and par value)  

Cash and cash equivalents

   $ 1,336      $ 1,451      $ 526   
  

 

 

   

 

 

   

 

 

 

Long-term debt:

      

WildHorse revolving credit facility(2)

     108,500        108,500        —     

Esquisto revolving credit facility(3)

     —          125,000        —     

Esquisto notes payable to members

     —          9,625        —     

New revolving credit facility(4)

     —          —          84,000   
  

 

 

   

 

 

   

 

 

 

Total long-term debt

   $ 108,500      $ 243,125      $ 84,000   
  

 

 

   

 

 

   

 

 

 

Members’/Stockholders’ equity:

      

Members’ equity

     337,974        —          —     

Common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; 62,518,680 shares issued and outstanding, as adjusted; 500,000,000 shares authorized, 91,000,000 shares issued and outstanding, as further adjusted

     —          625        910   

Additional paid-in capital

     —          610,552        1,145,393   

Accumulated deficit

     (77,378     (79,640     (80,487
  

 

 

   

 

 

   

 

 

 

Total owners’ and stockholders’ equity

   $ 260,596      $ 531,537      $ 1,065,816   
  

 

 

   

 

 

   

 

 

 

Total capitalization

   $ 369,096      $ 774,662      $ 1,149,816   
  

 

 

   

 

 

   

 

 

 

 

(1)

A $1.00 increase (decrease) in the assumed initial public offering price of $20.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) each of additional paid-in capital, total equity and total capitalization by approximately $26.0 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at

 

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  an assumed offering price of $20.00 per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) each of additional paid-in capital, total stockholders’ equity and total capitalization by approximately $18.9 million after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(2) As of November 21, 2016, total borrowings under the WildHorse revolving credit facility were approximately $110.3 million, and WildHorse expects to draw approximately $1.7 million in additional borrowings under such facility prior to the completion of this offering to fund capital expenditures, resulting in approximately $112.0 million of outstanding borrowings under its credit facility prior to the completion of this offering.
(3) As of November 21, 2016, total borrowings under the Esquisto revolving credit facility were approximately $145.0 million, and Esquisto expects to draw approximately $10.0 million in additional borrowings under such facility prior to the completion of this offering to fund capital expenditures, resulting in approximately $155.0 million of outstanding borrowings under its credit facility prior to the completion of this offering.
(4) We expect to draw approximately $118.8 million under our new revolving credit facility in connection with the consummation of this offering. The amount we expect to draw exceeds the as further adjusted amount set forth in the Capitalization table as a result of the additional borrowings under the WildHorse and Esquisto revolving credit facilities since September 30, 2016 described in notes (2) and (3) above and additional accrued interest on the Esquisto notes payable to members since that date.

 

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DILUTION

Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value (tangible assets less total liabilities) per share of our common stock for accounting purposes. Our pro forma net tangible book value as of September 30, 2016, after giving effect to the Corporate Reorganization, was approximately $531.5 million, or $8.50 per share.

Pro forma net tangible book value per share is determined by dividing our net tangible book value, or total tangible assets less total liabilities, by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to the Corporate Reorganization. Assuming an initial public offering price of $20.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us), our adjusted pro forma net tangible book value as of September 30, 2016 would have been approximately $1,066 million, or $11.71 per share. This represents an immediate increase in the net tangible book value of $3.21 per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $8.29 per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

 

Assumed initial public offering price per share

      $ 20.00   

Pro forma net tangible book value per share as of September 30, 2016 (after giving effect to the Corporate Reorganization)

   $ 8.50      

Increase per share attributable to new investors in this offering

     3.21      
  

 

 

    

As adjusted pro forma net tangible book value per share (after giving effect to the Corporate Reorganization and this offering)

        11.71   
     

 

 

 

Dilution in pro forma net tangible book value per share to new investors in this offering

      $ 8.29   
     

 

 

 

A $1.00 increase (decrease) in the assumed initial public offering price of $20.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $0.29 and increase (decrease) the dilution to new investors in this offering by $0.71 per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, on an adjusted pro forma basis as of September 30, 2016, the total number of shares of common stock owned by Existing Owners and to be owned by new investors at $20.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus) and the total consideration paid and the average price per share paid by our Existing Owners and to be paid by new investors in this offering at $20.00 (which is the midpoint of the price range set forth on the cover page of this prospectus) calculated before deduction of estimated underwriting discounts and commissions.

 

     Shares Acquired     Total Consideration     Average Price
Per Share
 
     Number      Percent     Amount     Percent    

Existing Owners

     62,518,680         68.7   $ 531,537,000 (1)      48.3   $ 8.50   

Rosewood Acquisition sellers

     981,320         1.1        19,626,000        1.8        20.00   

New investors in this offering

     27,500,000         30.2        550,000,000        49.9        20.00   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Total

     91,000,000         100.0   $ 1,101,163,000        100.0   $ 12.10   
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Represents the combined net members equity associated with the membership interests in WildHorse, Esquisto and Acquisition Co. to be contributed by the Existing Owners to WildHorse Resource

 

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  Development Corporation in connection with the offering. To date, the Existing Owners have made contributions of $625.2 million in cash to WildHorse and Esquisto on a combined basis representing $10.00 per share of common stock.

The data in the table excludes 4,512,500 shares of common stock reserved for issuance under our LTIP (which amount may be increased each year in accordance with the terms of our LTIP) and does not include 265,000 restricted shares of our common stock expected to be issued to certain officers and directors in connection with the successful completion of this offering pursuant to our LTIP. See “Executive Compensation—Narrative Disclosures—Compensation Following This Offering—IPO Bonuses” for more information. If the underwriters’ over-allotment option is exercised in full, the number of shares held by new investors will be increased to 31,625,000, or approximately 33.2% of the total number of shares of common stock.

 

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SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

WildHorse Development was formed as a holding company in August 2016, has not had any operations since its formation and does not have historical operating results. Accordingly, the following table shows selected historical consolidated financial data, for the periods and as of the dates indicated, of WildHorse Development’s accounting predecessor, WildHorse.

The selected historical consolidated financial data as of and for the years ended December 31, 2014 and 2015 were derived from the audited historical consolidated financial statements of WildHorse, our predecessor, included elsewhere in this prospectus.

The selected historical consolidated financial data as of and for the nine months ended September 30, 2015 and 2016 were derived from the unaudited historical consolidated financial statements of WildHorse included elsewhere in this prospectus. The selected unaudited historical consolidated financial data has been prepared on a consistent basis with the audited consolidated financial statements of WildHorse. In the opinion of management, such selected unaudited historical consolidated interim financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present the financial position and results of operations of our predecessor for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year.

The selected unaudited pro forma statement of operations data for the year ended December 31, 2014 has been prepared to give pro forma effect to (i) the Corporate Reorganization and (ii) the contribution of the Initial Esquisto Assets to Esquisto as part of its formation as if they had occurred on January 1, 2014. The selected unaudited pro forma statements of operations data for the year ended December 31, 2015 and the nine months ended September 30, 2015 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The selected unaudited statement of operations data for the nine months ended September 30, 2016 and the selected unaudited pro forma balance sheet data as of September 30, 2016 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015 and September 30, 2016, respectively. Please see “Use of Proceeds.” This data is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Prospectus Summary—Corporate Reorganization,” the historical consolidated financial statements of WildHorse and the unaudited pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

 

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    Predecessor Historical     Pro Forma  
    Year Ended
December 31,
    Nine Months Ended
September 30,
    Year Ended
December 31,
    Nine Months Ended
September 30,
 
    2014     2015     2015     2016     2014     2015     2015     2016  
          (Unaudited)     (Unaudited)  
          (In thousands, except per share data)  

Statement of Operations Data:

               

Revenues:

               

Oil sales

  $ 2,780      $ 3,305      $ 2,240      $ 2,971      $ 17,826      $ 142,614      $ 112,087      $ 86,279   

Natural gas sales

    37,741        30,556        23,381        25,273        38,345        38,063        29,199        29,560   

NGL sales

    989        1,451        1,100        658        2,285        6,722        5,069        4,428   

Gathering system income

    —          314        —          1,158        —          314        —          1,158   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    41,510        35,627        26,721        30,061        58,456        187,714        146,355        121,425   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses:

               

Lease operating expenses

    9,428        8,606        6,178        4,543        10,540        35,339        26,272        21,865   

Gathering system operating expense

    —          914        317        99        —          914        317        99   

Production and ad valorem taxes

    2,584        2,666        1,891        1,843        3,405        12,991        9,915        8,600   

Cost of oil sales

    687        —          —          —          687        —          —          —     

Depreciation, depletion and amortization

    15,297        25,526        17,516        27,305        23,269        99,009        71,834        79,519   

Impairment of proved oil and gas properties

    24,721        9,312        8,032        —          24,721        9,312        8,032        —     

General and administrative expenses

    5,838        10,567        7,475        8,399        8,226        16,611        11,707        14,058   

Exploration expense

    1,597        14,896        14,306        8,973        1,599        17,863        14,512        8,975   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expense

    60,152        72,487        55,715        51,162        72,447        192,039        142,589        133,116   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gain (loss) from operations

    (18,642     (36,861     (28,994     (21,102     (13,991     (4,326     3,766        (11,691
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense):

               

Interest expense

    (2,680     (2,576     (2,249     (2,732     (3,286     (4,185     (3,135     (3,135

Other income (expense)

    213        (45     9        (76     (120     (150     (472     (429

Gain (loss) on derivatives instruments

    6,514        9,510        6,063        (2,894     6,514        13,854        7,179        (8,694
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

    4,047        6,889        3,823        (5,702     3,108        9,519        3,572        (12,258
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net gain (loss) before income taxes

    (14,595     (29,972     (25,171     (26,804     (10,883     5,193        7,338        (23,949

Income tax benefit (expense)

    158        17        82        (15     4,502        (832     (1,759     9,595   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net (loss) income

  $ (14,437   $ (29,955   $ (25,089   $ (26,819   $ (6,381   $ 4,361      $ 5,579      $ (14,354
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net loss per common share:

               

Basic and diluted

          $ (0.07   $ 0.05      $ 0.06      $ (0.16

Weighted average common shares outstanding:

               

Basic and diluted

            91,000        91,000        91,000        91,000   

Cash Flow Data:

               

Net cash provided by (used in) operating activities

  $ 25,660      $ 25,374      $ 10,894      $ (9,542        

Net cash used in investing activities

  $ (128,968   $ (147,321   $ (109,842   $ (15,055        

Net cash provided by financing activities

  $ 114,589      $ 131,984      $ 118,594      $ 3,708           

Other Financial Data:

               

Adjusted EBITDAX(1)

          $ 32,120      $ 132,906      $ 104,381      $ 81,726   

Balance Sheet Data (at period end):

               

Cash and cash equivalents

  $ 12,188      $ 22,225      $ 31,835      $ 1,336            $ 526   

Total assets

  $ 335,722      $ 427,850      $ 420,073      $ 390,990            $ 1,322,390   

Total liabilities

  $ 156,730      $ 153,715      $ 160,963      $ 130,394            $ 276,200   

Owners’ equity

  $ 178,992      $ 274,134      $ 259,110      $ 260,596            $ 1,046,190   

Total liabilities and owners’ equity

  $ 335,722      $ 427,850      $ 420,073      $ 390,990            $ 1,322,390   

 

(1) Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net (loss) income, see “Prospectus Summary—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 Consolidated and Unaudited Pro Forma Financial Data” and the accompanying financial statements and 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 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, drilling results, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement 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. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

The pro forma statement of operations data for the year ended December 31, 2014 has been prepared to give pro forma effect to (i) the Corporate Reorganization and (ii) the contribution of the Initial Esquisto Assets to Esquisto as part of its formation as if they had occurred on January 1, 2014. The unaudited pro forma statements of operations data for the year ended December 31, 2015 and the nine months ended September 30, 2015 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Comstock Acquisition, (iii) the Burleson North Acquisition and (iv) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The pro forma statement of operations data for the nine months ended September 30, 2016 and the pro forma balance sheet data as of September 30, 2016 have been prepared to give pro forma effect to (i) the Corporate Reorganization, (ii) the Burleson North Acquisition and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015 and September 30, 2016, respectively.

WildHorse Resource Development Corporation

We are a growth-oriented, independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in two basins with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. Our acreage position is focused in two areas, Southeast Texas and North Louisiana. In Southeast Texas, we operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale, which is one of the most active shale trends in North America. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the overpressured Cotton Valley play.

We were formed as a Delaware corporation in August 2016 to serve as a holding company and have not had any operations since our formation. As a result, we do not have historical financial operating results, and our accounting predecessor is WildHorse. WildHorse, Esquisto and Acquisition Co. will be contributed to us in connection with this offering. Acquisition Co. was formed for the sole purpose of acquiring the Burleson North Assets. The Burleson North Acquisition is expected to be consumated prior to or contemporaneously with the completion of this offering. Please see “Prospectus Summary—Corporate Reorganization,” for a description of our Corporate Reorganization and “—Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Operations of Our Predecessor” for discussion of important factors that may cause our future results of operations to differ from the historical results of operations of our predecessor. Further, certain information is presented herein on a pro forma basis to give effect to, among other things, the Corporate Reorganization and the Burleson North Acquisition. Please see “—Pro Forma Results of Operations and Operating Expense—Pro Forma Adjustments” for a description of the pro forma adjustments that we made for each period presented.

 

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Overview

Market Conditions

The oil and natural gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and the first half of 2016, the global oil supply continued to outpace demand, resulting in a decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort 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. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the excess storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and in the first half of 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to 2014, our pro forma realized oil price for 2015 fell 47% to $45.99 per barrel, and our pro forma realized oil price for the nine months ended September 30, 2016 has further decreased to $38.40 per barrel. Similarly, compared to 2014, our pro forma realized natural gas price for 2015 decreased 43% to $2.27 per Mcf and our pro forma realized price for NGLs declined 53% to $11.92 per barrel. For the nine months ended September 30, 2016, our pro forma realized price for natural gas was $2.00 per Mcf and our pro forma realized price for NGLs was $10.88 per barrel.

Lower oil, natural gas and NGL prices not only reduce our revenues and cash flows, but also may limit the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our reserves. Lower commodity prices in the future could also result in impairments of our oil and natural gas properties and may also reduce the borrowing base under our new revolving credit facility, which will be determined by the lenders, in their sole discretion, based upon projected revenues from our oil, natural gas and NGL properties and our commodity derivative contracts. The occurrence of any of the foregoing could materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Alternatively, higher oil, natural gas and NGL prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses when oil and natural gas prices rise.

Drilling Activity

WildHorse

WildHorse commenced drilling with one rig in June 2014 and added a second rig in July 2014. During 2014, WildHorse completed two successful horizontal wells. WildHorse started 2015 running two rigs. In July 2015, WildHorse reduced its drilling program to one rig in response to low commodity prices and continued operating a one-rig drilling program through the end of 2015. During 2015, WildHorse completed seven successful horizontal wells and one vertical well. WildHorse started 2016 running one rig but released that rig in March 2016 in response to low commodity prices. WildHorse drilled and completed two horizontal wells, and participated in a third horizontal well that was drilled and completed by another operator, during the nine months ended September 30, 2016. In our North Louisiana Acreage, we intend to recommence drilling by adding one rig in late 2016 and one rig in 2017.

 

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Esquisto

During 2014, Esquisto drilled and completed five successful operated horizontal wells, utilizing one rig for the majority of the year, and participated in another eleven successful horizontal wells drilled by other operators. During 2015, Esquisto ran one rig until July when a second rig was added around the time of the Comstock Acquisition. During 2015, Esquisto drilled and completed a total of 18 successful horizontal wells and participated in another seven successful horizontal wells drilled by other operators. In early October 2015, Esquisto reduced its drilling program to one rig, which it ran until February 2016, at which point it ceased drilling due to the commodity price environment. Esquisto drilled and completed two successful operated horizontal wells during the three months ended March 31, 2016. During the second quarter of 2016, Esquisto recommenced drilling under a one-rig drilling program and drilled and completed a total of eight successful operated horizontal wells during the second and third quarters of 2016. In our Eagle Ford Acreage, we are currently running a one-rig program and intend to add three additional drilling rigs in 2017.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, the sale of NGLs that are extracted from our natural gas during processing, and the gathering charge paid by certain third parties for their share of volumes that run through our gathering system. For the nine months ended September 30, 2016, of our pro forma revenues, 71% came from oil sales, 24% came from natural gas sales, 4% came from NGL sales and 1% came from gathering charges. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. See “—Overview—Market Conditions” for information regarding the current commodity price environment. A $1.00 per barrel change in our realized oil price would have resulted in a $2.2 million change in pro forma oil sales for the nine months ended September 30, 2016. A $0.15 per Mcf change in our realized natural gas price would have resulted in a $2.2 million change in our pro forma natural gas sales for the nine months ended September 30, 2016. A $1.00 per barrel change in NGL prices would have changed pro forma NGL sales by $0.4 million for the nine months ended September 30, 2016.

The following table presents our pro forma average realized commodity prices, as well as the effects of derivative settlements during the periods indicated.

 

     Nine Months Ended
September 30,
     Year Ended
December 31,
 
     2016      2015      2015      2014  

Crude Oil (per Bbl):

           

Average NYMEX price

   $ 41.33       $ 51.00       $ 48.80       $ 93.00   

Realized price, before the effects of derivative settlements

   $ 38.40       $ 48.47       $ 45.99       $ 86.13   

Effects of derivative settlements

   $ 0.88       $ 0.16       $ 0.33         —     

Natural Gas:

           

Average NYMEX price (per MMBtu)

   $ 2.29       $ 2.80       $ 2.66       $ 4.41   

Realized price, before the effects of derivative settlements (per Mcf)

   $ 2.00       $ 2.46       $ 2.27       $ 4.01   

Effects of derivative settlements (per Mcf)

   $ 0.25       $ 0.59       $ 0.65       $ (0.28

NGLs (per Bbl):

           

Average realized NGL price

   $ 10.88       $ 12.12       $ 11.92       $ 25.55   

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials for these products.

 

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See “—Pro Forma Results of Operations and Operating Expense” and “—Predecessor Results of Operations and Operating Expense” below for an analysis of the impact changes in realized prices had on our revenues.

Production Results

The following table presents pro forma production volumes for our properties during the periods indicated:

 

     Nine Months Ended
September 30,
     Year Ended
December 31,
 
     2016      2015      2015      2014  

Oil (MBbls)

     2,246.9         2,312.5         3,100.9         207.0   

Natural gas (MMcf)

     14,766.3         11,875.4         16,766.7         9,551.7   

NGLs (MBbls)

     407.0         418.2         564.1         89.4   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total (MBoe)

     5,114.9         4,709.9         6,459.5         1,888.4   

Average net daily production (MBoe/d)

     18.7         17.3         17.7         5.2   

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil and natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost effective manner and to timely obtain drilling permits and regulatory approvals. Our ability to add reserves through drilling projects and acquisitions is dependent on many factors, including our ability to generate cash flow from operations, 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 Business” for a discussion of these and other risks affecting our proved reserves and production.

Derivative Activity

Oil, natural gas and NGL prices are volatile and unpredictable, and we expect this volatility to continue in the future. Due to this volatility, we have historically used commodity derivative instruments, such as collars, puts and swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGL prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil, natural gas and NGL prices and may partially limit our potential gains from future increases in prices. See “—Quantitative and Qualitative Disclosure About Market Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.

We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices. However, in times of low commodity prices, our ability to enter into additional commodity derivative contracts with favorable commodity price terms may be limited, which may adversely impact our future revenues and cash flows as compared to historical periods during which we were able to hedge our oil and natural gas production at higher prices. For example, as illustrated by the following tables, we have from time to time been able to hedge our production at prices higher that the prices associated with our current commodity derivative contracts. Specifically, our natural gas derivative contracts covering all or part of 2014 were at a weighted

 

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average price of more than $4.00 per MMBtu while the weighted average price of our current natural gas derivative contracts is significantly below $4.00 per MMBtu. Likewise, the weighted average price associated with our natural gas derivative contracts covering all or part of 2015 was higher than the weighted average price associated with our existing natural gas derivative contracts. We have not experienced a significant change in the price at which we have hedged our oil production due to the fact that we did not start hedging our oil production until 2015 following the significant decline in commodity prices during the second half of 2014. The following tables below provide additional information about our historical hedging activity and results as well as a summary of our existing hedges as of November 1, 2016.

The following table summarizes the notional quantity and weighted average price for all hedges that were entered into by WildHorse and on a pro forma basis covering all or part of the first nine months of 2016. We will not acquire any hedges from Clayton Williams Energy, Inc. in connection with the Burleson North Acquisition.

 

     WildHorse      Pro Forma  

Commodity

   Notional
Quantity
1/1/2016 -
9/30/2016
     Weighted
Average

Price
     Notional
Quantity
1/1/2016 -
9/30/2016
     Weighted
Average

Price
 

Crude oil swaps (Bbls)

     18,000       $ 50.41         370,212       $ 47.22   

Crude oil puts (Bbls)

     —           —           87,783       $ 50.00   

Natural gas swaps (MMBtu)

     4,790,000       $ 2.91         4,790,000       $ 2.91   

Natural gas collars (MMBtu)

     2,314,286       $ 2.71-$3.03         2,314,286       $ 2.71-$3.03   

The following table summarizes the historical results of hedging activities for WildHorse on a pro forma basis for the nine months ended September 30, 2016:

 

     Nine Months  Ended
September 30, 2016
 
     WildHorse      Pro Forma  

Average realized prices before effects of hedges:

     

Oil (Bbl)

   $ 45.39       $ 38.40   

Natural gas (Mcf)

   $ 2.01       $ 2.00   

NGL (Bbl)

   $ 13.42       $ 10.88   

Average realized prices after effects of hedges:

     

Oil (Bbl)

   $ 48.67       $ 39.28   

Natural gas (Mcf)

   $ 2.30       $ 2.25   

NGL (Bbl)

   $ 13.42       $ 10.88   

The following table summarizes the notional quantity and weighted average price for all hedges that were entered into by WildHorse and on a pro forma basis covering all or part of 2015:

 

     WildHorse      Pro Forma  

Commodity

   Notional
Quantity
1/1/2015 -
12/31/2015
     Weighted
Average
Price
     Notional
Quantity
1/1/2015 -
12/31/2015
     Weighted
Average
Price
 

Crude oil swaps (Bbls)

     14,000       $ 61.81         101,228       $ 51.91   

Crude oil puts (Bbls)

     —           —           104,759       $ 50.00   

Natural gas swaps (MMBtu)

     10,737,362       $ 3.65         10,737,362       $ 3.65   

 

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The following table summarizes the historical results of hedging activities for WildHorse on a pro forma basis for the year ended December 31, 2015:

 

     Year Ended
December 31, 2015
 
     WildHorse      Pro Forma  

Average realized prices before effects of hedges:

     

Oil (Bbl)

   $ 45.20       $ 45.99   

Natural gas (Mcf)

     2.24         2.27   

NGL (Bbl)

     14.05         11.92   

Average realized prices after effects of hedges:

     

Oil (Bbl)

   $ 47.16       $ 46.32   

Natural gas (Mcf)

     3.04         2.92   

NGL (Bbl)

     14.05         11.92   

The following table summarizes the notional quantity and weighted average price for all hedges that were entered into by WildHorse and on a pro forma basis covering all or part of 2014:

 

     WildHorse      Pro Forma  

Commodity

   Notional
Quantity
1/1/2014 -
12/31/2014
     Weighted
Average

Price
     Notional
Quantity
1/1/2014 -
12/31/2014
     Weighted
Average

Price
 

Natural gas swaps (MMBtu)

     7,090,000       $ 4.01         7,090,000       $ 4.01   

Natural gas collars (MMBtu)

     700,000       $ 4.25-$5.20         700,000       $ 4.25-$5.20   

The following table summarizes the historical results of hedging activities for WildHorse and on a pro forma basis for the year ended December 31, 2014:

 

     Year Ended
December 31, 2014
 
     WildHorse      Pro Forma  

Average realized prices before effects of hedges:

     

Oil (Bbl)

   $ 90.59       $ 86.13   

Natural gas (Mcf)

     4.02         4.01   

NGL (Bbl)

     23.90         25.55   

Average realized prices after effects of hedges:

     

Oil (Bbl)

   $ 90.59       $ 86.13   

Natural gas (Mcf)

     3.73         3.73   

NGL (Bbl)

     23.90         25.55   

The following tables provide a summary of the financial derivative contracts to which our predecessor and Esquisto on a combined basis were a party as of November 1, 2016:

 

Commodity / Term

  

Contract
Type

   Average Monthly
Volume (MMBtu)
     Weighted Average
Price per Unit
 

Natural Gas:

        

November 2016—December 2016

   Swaps      740,000       $ 2.880   

January 2017—December 2017

   Swaps      630,000       $ 3.100   

January 2018—December 2018

   Swaps      170,000       $ 2.945   

November 2016—December 2016

   Collars      460,000       $ 2.620 – $2.940   

January 2017—December 2017

   Collars      460,000       $ 3.000 – $3.362   

 

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Commodity / Term

   Contract
Type
     Average Monthly
Volume (Bbls)
     Weighted Average
Price per Unit
 

Crude Oil:

        

November 2016—December 2016

     Swaps         75,200       $ 46.430   

January 2017—December 2017

     Swaps         65,950       $ 49.200   

January 2018—December 2018

     Swaps         47,000       $ 51.040   

January 2019—December 2019

     Swap         5,000       $ 55.050   

November 2016—June 2018