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Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on October 1, 2014

Registration No. 333-            

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

MEMORIAL RESOURCE DEVELOPMENT CORP.

(Exact name of registrant as specified in its charter)

 

Delaware   1311   46-4710769

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

 

1301 McKinney Street, Suite 2100

Houston, Texas 77010

(713) 588-8300

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

 

Kyle N. Roane

Vice President, General Counsel and Corporate Secretary

Memorial Resource Development Corp.

1301 McKinney Street, Suite 2100

Houston, Texas 77010

(713) 588-8300

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

 

With copies to:

John Goodgame

Shar Ahmed

Akin Gump Strauss Hauer & Feld LLP

1111 Louisiana Street, 44th Floor

Houston, TX 77002

(713) 220-5800

 

Douglas E. McWilliams

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, TX 77002

(713) 758-2222

 

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

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   x  (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(2)
 

Amount of

Registration Fee

Common Stock, $0.01 par value per share

  31,968,125    $26.98    $862,500,000   $100,222.50

 

 

(1)   Includes shares of common stock that may be sold to cover the exercise of an option to purchase additional shares granted to the underwriters.
(2)   Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) under the Securities Act of 1933, as amended, and based on a price of $26.98, which is the average of the high and low trading prices per share as reported by the NASDAQ Global Select Market on September 30, 2014.

 

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 which 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 Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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Index to Financial Statements

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

 

SUBJECT TO COMPLETION, DATED OCTOBER 1, 2014

 

PRELIMINARY PROSPECTUS

 

27,798,368 Shares

 

LOGO

 

Memorial Resource Development Corp.

 

Common Stock

 

$         per share

 

 

 

MRD Holdco LLC and certain former management members of WildHorse Resources, LLC (collectively, the “selling stockholders”) are offering 27,798,368 shares of Memorial Resource Development Corp.’s common stock. The selling stockholders have granted the underwriters a 30-day option to purchase up to an additional 4,169,757 shares of common stock. We will not receive any proceeds from the sale of shares by the selling stockholders, including any shares that the selling stockholders may sell pursuant to the underwriters’ option to purchase additional shares of common stock.

 

Our common stock is listed on the NASDAQ Global Select Market under the symbol “MRD.” We are a “controlled company” as defined under the NASDAQ listing rules because the group consisting of affiliates of Natural Gas Partners beneficially owns over 50% of our shares of outstanding common stock. See “Principal and Selling Stockholders.”

 

On September 30, 2014, the last reported sale price of our common stock on the NASDAQ Global Select Market was $27.11 per share.

 

 

 

Investing in our common stock involves risks that are described in the “Risk Factors” section beginning on page 22 of this prospectus.

 

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 “Summary—Emerging Growth Company Status.”

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

 

     Per Share      Total  

Public Offering Price

   $                    $                

Underwriting Discounts and Commissions(1)

   $         $     

Proceeds, Before Expenses, to the Selling Stockholders

   $         $     

 

(1)   See “Underwriting” for a description of underwriting compensation payable in connection with this offering.

 

The underwriters expect to deliver the shares of common stock on or about                     , 2014.

 

 

 

Citigroup

 

 

 

The date of this prospectus is                     , 2014.


Table of Contents
Index to Financial Statements

LOGO


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

     Page  

SUMMARY

     1   

RISK FACTORS

     22   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     48   

USE OF PROCEEDS

     50   

DIVIDEND POLICY

     50   

MARKET PRICE OF OUR COMMON STOCK

     51   

SELECTED HISTORICAL FINANCIAL DATA

     52   

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

     55   

BUSINESS

     94   

MANAGEMENT

     129   

PRINCIPAL AND SELLING STOCKHOLDERS

     144   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     147   

DESCRIPTION OF CAPITAL STOCK

     152   

SHARES ELIGIBLE FOR FUTURE SALE

     157   

MATERIAL TAX CONSEQUENCES TO NON-U.S. HOLDERS

     159   

UNDERWRITING

     163   

LEGAL MATTERS

     169   

EXPERTS

     169   

WHERE YOU CAN FIND MORE INFORMATION

     170   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A: GLOSSARY OF OIL AND NATURAL GAS TERMS

     A-1   

APPENDIX B-1: NETHERLAND, SEWELL  & ASSOCIATES, INC. SUMMARY OF MEMORIAL RESOURCE DEVELOPMENT LLC PROVED RESERVES

     B-I-1   

APPENDIX B-2: NETHERLAND, SEWELL  & ASSOCIATES, INC. AUDIT LETTER REGARDING MEMORIAL RESOURCE DEVELOPMENT LLC PROBABLE AND POSSIBLE RESERVES

     B-II-1   

 

 

 

You should rely only on the information contained in this prospectus. Neither we, the selling stockholders, nor the underwriters have authorized any person to provide you with any information or represent anything about us or this offering that is not contained in this prospectus. If given or made, any such other information or representation should not be relied upon as having been authorized by us. The selling stockholders are not making an offer in any jurisdiction where an offer or sale is not permitted. The information contained in this prospectus is current only as of its date.

 

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Index to Financial Statements

Commonly Used Defined Terms

 

As used in this prospectus, unless we indicate otherwise:

 

   

“the Company,” “we,” “our,” “us” and “our company” or like terms refer collectively to (i) Memorial Resource Development Corp. and its subsidiaries (other than MEMP and its subsidiaries) for periods after the restructuring transactions described below and (ii) our predecessor (as described below) other than MEMP and its subsidiaries for periods prior to the restructuring transactions;

 

   

“selling stockholders” refers to MRD Holdco LLC and the certain former management members of WildHorse Resources, LLC named herein;

 

   

“Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires. We own the general partner of MEMP as well as 50% of MEMP’s incentive distribution rights;

 

   

“MEMP GP” refers to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own;

 

   

“MRD Holdco” refers to MRD Holdco LLC, a holding company controlled by the Funds that, together as part of a group owns a majority of our common stock;

 

   

“MRD LLC” refers to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC, our subsidiary, subsequent to our initial public offering;

 

   

“WildHorse Resources” refers to WildHorse Resources, LLC, which owns our interest in the Terryville Complex and is our 100% owned subsidiary;

 

   

“our predecessor” refers collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone, MRD Operating LLC, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries;

 

   

“the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively own MRD Holdco;

 

   

“restructuring transactions” means the transactions described beginning on page 12 that took place in connection with and shortly after the closing of our initial public offering, and pursuant to which we acquired substantially all of the assets of MRD LLC (not including its interests in BlueStone, MRD Royalty, MRD Midstream, Golden Energy Partners LLC or Classic Pipeline);

 

   

“BlueStone” refers to BlueStone Natural Resources Holdings, LLC, a subsidiary of MRD Holdco that sold substantially all of its assets in July 2013 for approximately $117.9 million;

 

   

“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;

 

   

“MRD Royalty” refers to MRD Royalty LLC, a subsidiary of MRD Holdco that owns certain immaterial leasehold interests and overriding royalty interests in Texas and Montana;

 

   

“MRD Midstream” refers to MRD Midstream LLC, a subsidiary of MRD Holdco that owns an indirect interest in certain immaterial midstream assets in North Louisiana; and

 

   

“Classic Pipeline” refers to Classic Pipeline & Gathering, LLC, a subsidiary of MRD Holdco that owns certain immaterial midstream assets in Texas.

 

Industry and Market Data

 

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is

 

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Index to Financial Statements

also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, neither we nor the selling stockholders have independently verified the information.

 

Equivalency

 

This prospectus presents certain production and reserves-related information on an “equivalency” basis. When we refer to oil and natural gas in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil and/or NGLs is equivalent to six Mcf of natural gas. This calculation is based on an approximate energy equivalency and does not imply or reflect a value or price relationship.

 

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Index to Financial Statements

SUMMARY

 

This summary highlights information appearing elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk Factors” beginning on page 22 and the historical and pro forma financial statements and the related notes to those financial statements. Certain oil and gas industry terms, including the terms proved reserves, probable reserves and possible reserves, used in this prospectus are defined in the “Glossary of Oil and Natural Gas Terms” in Appendix A of this prospectus.

 

Because we control MEMP through our ownership of its general partner, we are required to consolidate MEMP for accounting and financial reporting purposes even though we only own a minority of its limited partner interests. Our financial statements include two reportable business segments: (i) the MRD Segment, which reflects all of our operations except for MEMP and its subsidiaries, and (ii) the MEMP Segment, which reflects the operations of MEMP and its subsidiaries. Except with respect to our consolidated and combined financial statements or as otherwise indicated, the description of our business, properties, strategies and other information in this summary does not include the business, properties or results of operations of BlueStone, MRD Royalty, MRD Midstream and Classic Pipeline (the assets of which are included in our predecessor but were not conveyed to us in the restructuring transactions) or MEMP. Our proved reserves as of December 31, 2013 have been prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers (“NSAI”), and our probable and possible reserves as of December 31, 2013 have been prepared by our internal reserve engineers and audited by NSAI, all of which are reflected in our reserve reports (which we collectively refer to as our “reserve report”), summaries of which are included in Appendices B-1 and B-2 of this prospectus.

 

Information expressed on a pro forma basis in this summary gives effect to certain transactions as if they had occurred on June 30, 2014 for pro forma balance sheet purposes and on January 1, 2013 for pro forma statements of operations purposes. For a description of these transactions, please read “Summary Historical Consolidated and Combined Pro Forma Financial Data” and “—Corporate History and Structure.”

 

Overview

 

We are an independent natural gas and oil company focused on the exploitation, development, and acquisition of natural gas, NGL and oil properties with a majority of our activity in the Terryville Complex of North Louisiana, where we are targeting overpressured, liquids-rich natural gas opportunities in multiple zones in the Cotton Valley formation. As of December 31, 2013, our total leasehold position was 347,458 gross (205,818 net) acres, of which 60,041 gross (51,522 net) acres are in what we believe to be the core of the Terryville Complex. We are focused on creating shareholder value primarily through the development of our sizeable horizontal inventory. As of December 31, 2013, we had 1,582 gross (1,091 net) identified horizontal drilling locations, of which 1,431 gross (994 net) identified horizontal drilling locations are located in the Terryville Complex. These total net identified horizontal drilling locations represent an inventory of over 34 years based on our expected 2014 drilling program. We believe our inventory to be repeatable and capable of generating high returns based on the extensive production history in the area, the results of our horizontal wells drilled to date, and the consistent reservoir quality across multiple target formations.

 

As of December 31, 2013, we had estimated proved, probable and possible reserves of approximately 1,126 Bcfe, 800 Bcfe and 1,711 Bcfe, respectively. As of such date, we operated 98% of our proved reserves, 71% of which were natural gas. For the six months ended June 30, 2014, 55% of our pro forma MRD Segment revenues were attributable to natural gas production, 22% to NGLs and 23% to oil. For the six months ended June 30, 2014, we generated pro forma MRD Segment Adjusted EBITDA of $163 million and pro forma net loss of $924 million, and made pro forma capital expenditures of $166 million. For the year ended December 31, 2013, we generated pro forma MRD Segment Adjusted EBITDA of $159 million and pro forma net loss of $2.9 million, and made pro forma total capital expenditures of $203 million. Please see “—Summary Historical

 

 

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Index to Financial Statements

Consolidated and Combined Pro Forma Financial Data—Adjusted EBITDA” for an explanation of the basis for the pro forma presentation and our use of Adjusted EBITDA to measure the MRD Segment’s profitability.

 

Our average net daily production for the six months ended June 30, 2014 was approximately 196 MMcfe/d (approximately 75% natural gas, 17% NGLs and 8% oil) and our reserve life was 15.8 years. The Terryville Complex represented 84% of our total net production for the six months ended June 30, 2014. As of December 31, 2013, we produced from 95 horizontal wells and 800 vertical wells. Since January 1, 2014, in the Terryville Complex we have completed and brought online 10 horizontal wells through June 30, 2014, bringing our total number of producing horizontal wells to 31 in our primary formations.

 

The following chart provides information regarding our production growth and the increasing proportion of our horizontal well production since the beginning of 2012.

 

LOGO

 

Our Properties

 

Cotton Valley—Overview

 

The Cotton Valley formation extends across East Texas, North Louisiana and Southern Arkansas. The formation has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. Over 21,000 vertical wells have been completed throughout the play. In 2005, operators started redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. To date, operators have drilled over 600 horizontal Cotton Valley wells. Some large, analogous redevelopment projects in the Cotton Valley include the Nan-Su-Gail Field in Freestone County, East Texas, where over 40 horizontal wells have been drilled by operators such as Devon Energy Corporation and Marathon Oil Corporation, and the Carthage Complex in Panola County, East Texas, where operators such as ExxonMobil Corporation, BP America, Memorial Production Partners LP and Anadarko Petroleum Corporation have drilled over 153 horizontal wells.

 

 

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Index to Financial Statements

Cotton Valley—Terryville Complex Horizontal Redevelopment

 

We are currently engaged in the horizontal redevelopment of the Terryville Complex in Lincoln Parish, Louisiana utilizing horizontal drilling and completion techniques similar to those employed at the Nan-Su-Gail Field, Carthage Complex in East Texas and other major resource plays across the United States. We have assembled a largely contiguous acreage position in the Terryville Complex of approximately 60,041 gross (51,522 net) acres as of December 31, 2013. The majority of our current and planned development is focused in and around what we believe to be the core of the Terryville Complex.

 

We entered the Terryville Complex via an acquisition from Petrohawk Energy Corporation in April 2010, with the goal of redeveloping the field with horizontal drilling and modern completion techniques. Since that acquisition, we have completed multiple bolt-on acquisitions and in-fill leases to build our current position. We believe the Terryville Complex, which has been producing since 1954, is one of North America’s most prolific natural gas fields, characterized by high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked producing zones, available infrastructure and a large number of service providers.

 

After initially drilling eight vertical pilot wells in the Terryville Complex, we commenced a horizontal drilling program in 2011 to further delineate and define our position. In 2013, we shifted our operational focus to full-scale horizontal redevelopment of the Terryville Complex, going from two rigs to four rigs by the end of that year. Additionally, in the fourth quarter of 2013, we moved to drilling on multi-well pads that allow us to more efficiently drill wells and control costs as we develop our stacked pay zones. We intend to dedicate approximately $304 million of our $351 million drilling and completion budget in 2014 to develop multiple zones within the Terryville Complex, where we expect to drill 43 gross (37 net) horizontal wells and 3 gross (2.7 net) vertical wells. Our horizontal redevelopment program in the Terryville Complex will be focused on increasing our well performance and recoveries.

 

Within the Terryville Complex, as of December 31, 2013, we had 945 Bcfe, 688 Bcfe and 1,643 Bcfe of estimated proved, probable and possible reserves, respectively, and a drilling inventory consisting of 1,431 gross (994 net) identified horizontal drilling locations, including 91 gross (72 net) drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2013. Since initiating our horizontal drilling program in 2011, we have drilled 31 gross (27 net) horizontal wells. Within the Terryville Complex, on a proved reserves basis, we operate approximately 99% of our existing acreage and hold an average working interest of approximately 74% across our acreage. Our high operating control allows us to more efficiently and economically manage the redevelopment of this extensive resource.

 

We believe seismic data, as well as information gathered from the results of our existing 275 vertical and 31 horizontal wells throughout the field, support the existence of at least ten stacked pay zones across the Terryville Complex. Our redevelopment program currently targets four of the stacked pay zones in the Cotton Valley formation—zones we term the Upper Red, Lower Red, Lower Deep Pink and Upper Deep Pink, all of which we are developing with horizontal wells through pad drilling. These four zones have an overall thickness ranging from 400 to 890 feet across our acreage position. We believe the overpressured nature of this section of the Cotton Valley formation is highly productive when accessed through horizontal drilling and fracture stimulation technologies. These qualities, when combined with the liquids-rich nature of the natural gas, high initial rates of production and competitive well costs, produce what we believe to be amongst the highest rate of return wells in the nation. Further, there are additional opportunities for redevelopment in the zones above the four main zones. NSAI has audited over $1 billion PV-10 and 677 Bcfe in our possible reserve category for the redevelopment of these additional zones. Please see “—Reserves.”

 

 

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Index to Financial Statements

The table below details certain information on estimated ultimate recoveries and production for the 31 horizontal wells currently producing in the Terryville Complex. Our well results have shown consistency in initial production, decline rates and estimated ultimate recovery. The consistency of these results gives us confidence that the full-scale redevelopment of the Terryville Complex we began in 2013 will be successful as we move from four to six rigs for the remainder of 2014. Please see “Business—Our Properties—Cotton Valley—Terryville Complex Horizontal Redevelopment” for more detail on our properties in the Terryville Complex and the table on page 97 for more detail on the average EUR and cumulative production of our properties in the Terryville Complex.

 

    Lateral
Length

(Feet)
    Producing Wells           Cumulative
Production

(Bcfe)
    Gross Wellhead Flow Rates
After Processing

(MMcfe/d)(3)(4)
       
       EUR
(Bcfe)(2)
    EUR  Bcfe/
1,000’
    First
Production
    Days
Producing
        D&C
($MM)
 

Well Name(1)

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

Upper Red Zone

                     

LD Barnett 23H-2

    4,015        13.6        3.4        1/30/2012        883        4.8        14.5        12.0        7.7        5.6        6.7   

Colquitt 20 17H-1

    4,357        11.2        2.6        7/30/2012        701        4.0        17.5        12.6        7.2        5.1        7.7   

Dowling 22 15H-1

    5,376        16.8        3.1        9/22/2012        647        5.3        16.3        15.6        11.1        8.2        8.8   

Nobles 13H-1

    4,216        11.6        2.8        11/17/2012        591        4.4        21.5        16.7        9.9        6.5        7.8   

Sidney McCullin 16 21H-1

    4,604        16.9        3.7        1/19/2013        528        4.7        17.4        14.2        10.8        8.4        8.1   

Wright 14 11 HC-1

    5,250        18.0        3.4        5/27/2013        400        4.9        19.6        18.1        16.1        8.4        8.8   

BF Fallin 22 15H-1

    5,122        15.6        3.0        6/17/2013        379        3.4        14.8        13.7        11.8        5.9        7.5   

Dowling 20 17H-1

    4,327        8.9        2.1        7/22/2013        344        2.3        15.2        11.0        5.7          10.7   

Gleason 31H-1

    3,692        2.5        0.7        8/12/2013        323        0.5        2.9        2.3        1.8          9.5   

Burnett 26H-1

    2,405        4.2        1.7        9/22/2013        282        1.0        6.9        5.5        3.3          6.9   

Drewett 17 8H-1

    4,010        14.0        3.5        11/13/2013        230        3.2        22.1        18.7        12.0          7.7   

Wright 13 12 HC-2

    6,009        18.1        3.0        12/21/2013        192        3.4        22.7        19.6        16.2          8.6   

LA Minerals 15 22H-2

    5,814        N/A        N/A        1/21/2014        161        2.4        18.1        16.3            9.4   

Wright 13 24 HC-3

    6,606        N/A        N/A        4/14/2014        78        2.0        30.3              10.7   

Wright 13 24 HC-1

    6,678        N/A        N/A        4/14/2014        78        1.6        25.0              11.8   

TL McCrary 14 11 HC-5

    5,875        N/A        N/A        4/14/2014        78        1.8        22.9              10.2   

LA Minerals 19 30 HC-2

    6,912        N/A          5/29/2014        33        0.8        25.1              10.5   

LA Minerals 19 30 HC-1

    6,519        N/A          6/1/2014        30        0.6        21.8              11.6   

Lower Red Zone

                     

TL McCrary 14H-1

    4,544        12.8        2.8        5/1/2012        791        4.2        14.4        11.7        8.3        5.4        7.7   

Nobles 13H-2

    4,060        9.2        2.3        11/17/2012        591        3.2        16.0        11.9        8.4        5.2        7.8   

LA Methodist Orphanage 14H-1

    3,637        12.1        3.3        2/15/2013        501        3.8        13.9        13.0        9.7        6.3        9.1   

Dowling 21 16H-1

    4,590        9.4        2.0        3/18/2013        470        2.7        13.0        10.1        6.5        4.5        6.6   

Drewett 17 8H-2

    3,700        3.7        1.0        11/13/2013        230        1.0        8.7        6.2        3.1          7.0   

Wright 13 12 HC-1

    5,409        8.2        1.5        12/21/2013        192        1.7        14.7        11.4        7.2          9.3   

LA Minerals 15 22H-1

    5,926        N/A        N/A        1/21/2014        161        1.4        13.8        10.9            8.8   

Wright 13 24 HC-4

    6,518        N/A        N/A        4/14/2014        78        1.6        25.7              13.4   

LA Minerals 19 30 HC-3

    5,356        N/A        N/A        5/29/2014        33        0.3        8.8              12.1   

LA Minerals 19 30 HC-4

    6,469        N/A        N/A        6/1/2014        30        0.4        14.1              13.6   

Lower Deep Pink Zone

                     

LA Methodist Orphanage 14H-2

    3,550        12.2        3.4        2/15/2013        501        3.3        14.2        11.6        7.6        5.6        6.1   

Wright 13 12 HC-4

    5,010        5.0        1.0        12/21/2013        192        1.3        11.8        8.8        4.8          7.0   

Wright 13 12 HC-3

    5,706        6.3        1.1        12/21/2013        192        1.3        12.5        9.3        5.0          7.4   

Averages

                     

All Wells

    5,041        11.0        2.5          320        2.5        16.7        12.2        8.3        6.3        9.0   

Upper Red

    5,099        12.6        2.7          331        2.8        18.6        13.6        9.5        6.9        9.1   

Lower Red

    5,021        9.2        2.2          308        2.0        14.3        10.7        7.2        5.4        9.5   

Lower Deep Pink

    4,755        7.8        1.8          295        2.0        12.8        9.9        5.8        5.6        6.8   

 

(1)   The majority of the wells in this table are included within our proved developed producing reserve category in our reserve report as of December 31, 2013. LA Minerals 15 22H-1, LA Minerals 15 22H-2, TL McCrary 14 11 HC-5, Wright 13 24 HC-1, Wright 13 24 HC-3, Wright 13 24 HC-4, LA Minerals 19 30 HC-1, LA Minerals 19 30 HC-2, LA Minerals 19 30 HC-3 and LA Minerals 19 30 HC-4 each started producing in 2014 so they have not been included in the year-end reserve report as proved developed producing.
(2)   EUR represents the Estimated Ultimate Recovery or 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/condensates, gas and NGLs after the effects of processing.

 

 

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(3)   Production data is as of June 30, 2014 and shown gross on a combined basis after the effects of processing.
(4)   Periodic flow rates start on day 4, with days 1 through 3 used to allow clean up associated with well completion. The 30-day flow rates therefore start on day 4 and continue 30 days to day 33 and the 90-day flow rates go from day 4 to day 93.

 

East Texas

 

We own and operate approximately 54,337 gross (42,894 net) acres as of December 31, 2013 in Texas, where we are currently producing primarily from the Cotton Valley, Travis Peak and Bossier formations and targeting the Cotton Valley formation for future development. From January 1, 2011 through December 31, 2013, we have drilled and completed 28 gross (10.3 net) wells and are operating one rig in East Texas as of December 31, 2013. In 2014, we plan to invest $29 million to drill 4 gross (3 net) wells in East Texas in the Joaquin Field of Panola and Shelby Counties. As of December 31, 2013, we had approximately 108 gross identified horizontal drilling locations in East Texas, including 54 gross (43 net) drilling locations to which we have attributed proved undeveloped reserves as of December 31, 2013. For the six months ended June 30, 2014, our average net daily production from our East Texas properties was 25 MMcfe/d, of which 75% was natural gas. Within our East Texas properties, on a proved reserves basis, we operate approximately 91% of our existing properties.

 

Rockies

 

We own approximately 162,375 gross (66,191 net) acres as of December 31, 2013 in our Rockies region and for the six months ended June 30, 2014 our average net daily production from this region was 6 MMcfe/d. In 2014, we plan to invest $18 million to complete 2 gross (2 net) vertical wells in the Tepee Field of the Piceance Basin targeting the Mancos and Williams Fork formations. As of December 31, 2013, we had approximately 174 gross identified vertical drilling locations in the Tepee Field in our Rockies properties.

 

Reserves

 

Our estimates of proved reserves are prepared by NSAI, and our estimates of probable and possible reserves are prepared by our management and audited by NSAI. As of December 31, 2013, we had 1,126 Bcfe, 800 Bcfe and 1,711 Bcfe of estimated proved, probable and possible reserves, respectively. As of this date, our proved reserves were 71% gas and 29% NGLs and oil. Additionally, the PV-10 of our proved reserves was $1,469 million, the PV-10 for our probable reserves was $1,052 million and the PV-10 for our possible reserves was $2,386 million. The following table provides summary information regarding our estimated proved, probable and possible reserves data by area based on our reserve report as of December 31, 2013 and our average net daily production by area for the six months ended June 30, 2014:

 

    Proved
Total
(Bcfe)
    % Gas     % Developed     Proved
PV-10
(in millions)(1)
    Probable
Total
(Bcfe)(2)
    Probable
PV-10
(in millions)(1)
    Possible
Total
(Bcfe)(2)
    Possible
PV-10
(in millions)(1)
    Average
Net
Daily
Production
(MMcfe/d)
 

Terryville Complex

    945        71     33   $ 1,341        688      $ 1,032        1,643      $ 2,383        165   

East Texas

    175        75     29     110        109        18        66        3        25   

Rockies

    6        49     100     18        2        2        2        1        6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    1,126        71     33   $ 1,469        800      $ 1,052        1,711      $ 2,386        196   
 

 

 

       

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)  

In this prospectus, we have disclosed our PV-10 based on our reserve report. PV-10 is a non-GAAP financial measure and represents the period-end present value of estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for natural gas and oil of $3.67 per Mcf and $93.42 per Bbl was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2013. PV-10 differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes. Moreover, GAAP does not

 

 

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provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, we believe that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of our reserves in the absence of a comparable GAAP measure such as standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. In addition, investors should be cautioned that estimates of PV-10 for probable and possible reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Our PV-10 estimates of proved reserves and our standardized measure are equivalent because, prior to the completion of our initial public offering, we were not subject to entity level taxation. Accordingly, no provision for federal income taxes has been provided because taxable income for 2013 was passed through to our equity holders. However, had we not been a tax exempt entity as of December 31, 2013, our estimated discounted future income tax in respect of our proved, probable and possible reserves would have been approximately $401 million, $368 million and $835 million, respectively. Since the closing of our initial public offering, we are treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent upon our future taxable income. Neither PV-10 nor standardized measure represents an estimate of fair market value of our natural gas and oil properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

(2)   Substantially all of our estimated probable and possible reserves are classified as undeveloped.

 

Drilling Inventory and Capital Budget

 

We intend to develop our multi-year drilling inventory by utilizing our significant expertise in horizontal drilling and fracture stimulation to grow our production, reserves and cash flow. For 2014, we have budgeted a total of $351 million to drill 47 gross (39 net) operated horizontal wells. We expect to fund our 2014 development primarily from cash flows from operations. The majority of our drilling locations and our 2014 development program are focused on the Terryville Complex, where we plan to invest $304 million on drilling 43 gross (37 net) horizontal wells and 3 gross (2.7 net) vertical wells. In East Texas, we plan to invest $29 million on drilling and completing 4 gross (3 net) horizontal wells. In the Rockies, we plan to invest $18 million on completing 2 gross (2 net) vertical wells in the Tepee Field.

 

The following table provides information regarding our acreage and drilling locations by area as of December 31, 2013, except for projected 2014 information:

 

    Net
Acreage
    WI%     Gross Horizontal Drilling Locations(1)(2)     Net
Horizontal
Drilling

Inventory
(years)
    2014
Projected
Operated
Horizontal
Net Wells

to be
Drilled
    2014
Projected
Capital

Budget
($MM)
 
        Proved     Probable     Possible     Management     Total        
                Gross     Net        

Terryville Complex

    96,733        74     91        147        450        743        1,431        994        35        37      $ 304   

East Texas

    42,894        79     54        39        15        —          108        92        24        3        29   

Rockies

    66,191        41     —          23        20        —          43        4        —          —          18   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    205,818        59     145        209        485        743        1,582        1,091        34        39      $ 351   

 

(1)   The above table excludes 192 proved vertical drilling locations in our reserve report in the Terryville Complex and 174 identified vertical locations based on management estimates in the Rockies.
(2)   Please see “Business—Our Operations—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, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.” Proved, probable and possible locations are based on our reserve report. Management locations are based on management estimates of additional identified drilling locations.

 

 

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Our extensive inventory and horizontal drilling program in the Terryville Complex is currently focused on four zones within the Cotton Valley formation—the Upper Red, Lower Red, Lower Deep Pink and Upper Deep Pink. The table below sets forth our drilling locations by zone as of December 31, 2013 along with the average results for the wells we have drilled within each zone. Please see “Business—Our Properties—Cotton Valley—Terryville Complex Horizontal Redevelopment” for more detail on our properties in the Terryville Complex and the table on page 97 for the 30 day initial production rate and EUR condensate volumes.

 

Lower Cotton

Valley Zone

  Gross Horizontal Drilling Locations(1)     Average Historical Results(2)  
    Producing
Wells
Drilled(1)
    EUR
(Bcfe)(3)
    Drilling  and
Completion Costs
($MM)
 
  Proved     Probable     Possible     Management     Total        

Upper Red

    47        42        40        313        442        18        12.6      $ 9.1   

Lower Red

    40        40        36        276        392        10        9.2      $ 9.5   

Lower Deep Pink

    4        28        47        79        158        3        7.8      $ 6.8   

Upper Deep Pink

    —          37        42        75        154        —          —          —     

Other Zones

    —          —          285        —          285        —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Terryville Complex

    91        147        450        743        1,431        31        11.0      $ 9.0   

 

(1)   Please see “Business—Our Operations—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, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.” Proved, probable and possible locations are based on our reserve report. Management locations are based on management estimates of additional identified drilling locations.
(2)   Relates to the 21 horizontal wells in the Terryville Complex included in our reserve report as proved developed reserves as of December 31, 2013. Drilling and completion costs and producing wells drilled include ten additional wells that have come online since year-end.
(3)   EUR represents the Estimated Ultimate Recovery or 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 at the wellhead on a combined basis for oil/condensates and wet gas.

 

Our Terryville horizontal development program in 2014 has an average working interest of 86% and our total horizontal development inventory has an average working interest of 69%.

 

For the Terryville Complex, our 2014 budget assumes an average drilling and completion cost of $9.7 million for gross horizontal wells ($8.3 million per net well) and is based on an average lateral length of 6,233 feet. As part of our long-term development plan, the lateral length of our planned wells is expected to increase and we expect wells within the Terryville Complex to increase to a 7,500 foot lateral length.

 

Business Strategies

 

Our primary objective is to build shareholder value through growth in reserves, production and cash flows by developing and expanding our significant portfolio of drilling locations. To achieve our objective, 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 low-risk drilling locations, combined with our operating expertise, will enable us to continue to deliver production, reserve and cash flow growth and create shareholder value. As of December 31, 2013, we had assembled an aggregate drilling inventory of 1,582 gross identified horizontal drilling locations, 90% of which are in the Terryville Complex, representing a drilling inventory of over 35 years based on our expected 2014 drilling program. We believe that the risk and uncertainty associated with our core acreage positions in the Terryville Complex has been largely reduced through our development activity, and because those positions are in areas with extensive drilling and production history. Since initiating

 

 

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our horizontal drilling program with one rig in 2011, we have invested over $419 million in the Terryville Complex through June 30, 2014. With five rigs running in the Terryville Complex as of June 30, 2014, we are one of the most active drillers in the Cotton Valley formation. We intend to dedicate approximately $304 million of our $351 million drilling and completion budget in 2014 to develop the overpressured liquids-rich Terryville Complex through multi-well pad drilling. We believe multiple vertically stacked producing horizons in the Terryville Complex can be developed using horizontal drilling techniques, thus enhancing the economics of this field.

 

Enhance returns through prudent capital allocation and continued improvements in operational and capital efficiencies.    We continually monitor and adjust our drilling program with the objective of achieving the highest total returns on our portfolio of drilling opportunities. We believe we will achieve this objective by (i) minimizing the capital costs of drilling and completing horizontal wells through knowledge of the target formations, (ii) maximizing well production and recoveries by optimizing lateral length, the number of frac stages, perforation intervals and the type of fracture stimulation employed, (iii) targeting specific zones within our leasehold position to maximize our hydrocarbon mix based on the existing commodity price environment and (iv) minimizing operating costs through efficient well management.

 

Exploit additional development opportunities on current acreage.    Our existing asset base provides numerous opportunities for our highly experienced technical team to create shareholder value by increasing our inventory beyond our currently identified drilling locations and ultimately by growing our estimated proved reserves. In the Terryville Complex, we are currently targeting multiple stacked horizons. We also believe our East Texas region has a significant inventory of low-risk, liquids-rich horizontal drilling locations. Finally, we continue to evaluate our leasehold positions in the Rockies and have preliminarily identified over 170 potential vertical locations.

 

Maintain a disciplined, growth oriented financial strategy.    We intend to fund our growth primarily with internally generated cash flows while maintaining ample liquidity and access to the capital markets. Furthermore, we plan to hedge a significant portion of our expected production to reduce our exposure to downside commodity price fluctuations and enable us to protect our cash flows and maintain liquidity to fund our drilling program. Since approximately 76% of our acreage in the Terryville Complex was held by production as of December 31, 2013 and no significant drilling commitments are needed to hold our remaining acreage in the near term, we are able to allocate capital among projects in a manner that optimizes both costs and returns, resulting in a highly efficient drilling program.

 

Make opportunistic acquisitions that meet our strategic and financial objectives.    We will seek to acquire oil and gas properties that we believe complement our existing properties in our core areas of operation. In addition to our focus on the Terryville Complex, we are pursuing other properties that provide opportunities for the addition of reserves and production through a combination of exploitation, development, high-potential exploration and control of operations. We follow a technology driven strategy to establish large, contiguous leasehold positions in the core of prolific basins and opportunistically add to those positions through bolt-on acquisitions over time. We entered into the Terryville Complex through strategic acquisitions and grassroots leasing efforts, amassing a land position as of December 31, 2013 of 96,733 net acres, 51,522 net acres of which we believe to be in the core of the play. We will continue to identify and opportunistically acquire additional acreage and producing assets to complement our multi-year drilling inventory.

 

Competitive Strengths

 

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

 

Large, concentrated position in one of North America’s leading plays.    As of December 31, 2013, we owned approximately 60,041 gross (51,522 net) acres in what we believe to be the core of the Terryville

 

 

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Complex in Lincoln Parish, which we believe to be one of North America’s most prolific liquids-rich natural gas fields, characterized by consistent and predictable geology and multiple stacked pay formations confirmed by extensive vertical well control. Through December 31, 2013, our drilling program in the Terryville Complex has produced some of the top performing gas wells in the United States in the previous two years, with single horizontal well results having achieved EURs averaging 11.0 Bcfe per well. Through June 30, 2014, we have brought 31 wells online with average 30-day initial production rates of 16.7 MMcfe/d and average drilling and completion costs of $9.0 million per well. Approximately 76% of our acreage in the Terryville Complex was held by production at December 31, 2013 and there are no significant lease expirations until 2017. Additionally, all of our acreage in this play can be held by running a one-rig program over the next 18 months.

 

De-risked acreage position with multi-year inventory of liquids-rich drilling opportunities.    As of December 31, 2013, we had a drilling inventory consisting of 1,582 gross identified horizontal drilling locations, of which approximately 145 are gross proved undeveloped locations. Based on our expected 2014 drilling program and net identified drilling locations, we have over 34 years of liquids-rich drilling inventory. The majority of our drilling activity has been and will continue to be focused in the Terryville Complex, where we produce liquids-rich natural gas from the overpressured Cotton Valley formation. We have used subsurface data from our vertical wells coupled with 3-D seismic data to identify and prioritize our inventory based on returns. This liquids-rich gas formation allows for NGL processing that, when coupled with the condensate produced, results in strong well economics. For the six months ended June 30, 2014, 55% of our MRD Segment revenues were attributable to natural gas, 22% to NGLs and 23% to oil.

 

Significant operational control with low cost operations.    On a proved reserves basis, we operate 99% of our properties and have operational control of all of our drilling inventory in the Terryville Complex. We believe maintaining operational control will enable us to enhance returns by implementing more efficient and cost-effective operating practices, through the selection of economic drilling locations, opportunistic timing of development, continuous improvement of drilling, completion and stimulation techniques and development on multi-well pads. As a result of the contiguous nature of our leasehold in the Terryville Complex, its geologic continuity and cross unit lateral pooling, we are able to drill consistently long laterals, averaging over 5,041 lateral feet, which helps us to reduce costs on a per-lateral foot basis and increase our returns. We expect the average lateral length of the 43 gross wells that we expect to drill in the Terryville Complex in 2014 to be 6,233 feet per well. Operating in mature basins in North Louisiana and East Texas allows us to take advantage of the available and extensive midstream infrastructure and accelerate our development plan without encountering significant constraints in either takeaway or processing capacity. Our operational control allows us to focus on operating efficiency, which has resulted in our MRD Segment lease operating costs declining 35% from $0.51 per Mcfe for the six months ended June 30, 2013 to $0.33 per Mcfe for the six months ended June 30, 2014.

 

Proven and incentivized executive and technical team.    We believe our management and technical teams are one of our principal competitive strengths due to our team’s significant industry experience and long history of working together in the identification, execution and integration of acquisitions, cost efficient management of profitable, large scale drilling programs and a focus on rates of return. Additionally, our technical team has substantial expertise in advanced drilling and completion technologies and decades of expertise in operating in the North Louisiana and East Texas regions. The members of our management team collectively have an average of 22 years of experience in the oil and natural gas industry. John A. Weinzierl, our Chief Executive Officer, has 24 years of oil and natural gas industry experience as a petroleum engineer, a strong commercial and technical background and extensive experience acquiring and managing oil and natural gas properties. Our management team has a significant economic interest in us directly and through its equity interests in our controlling stockholder, MRD Holdco. We believe our management team is motivated to deliver high returns, create shareholder value and maintain safe and reliable operations.

 

Our relationship with MEMP.    We own a 0.1% general partner interest in MEMP through our ownership of its general partner as well as 50% of MEMP’s incentive distribution rights. MEMP’s objective as a master

 

 

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limited partnership is to generate stable cash flows, allowing it to make quarterly distributions to its limited partners and, over time, to increase those quarterly distributions. As a result of its familiarity with our management team and our asset base and our track record of prior “drop-down” transactions, we believe that MEMP is a natural purchaser of properties from us that meet its acquisition criteria. We believe this mutually beneficial relationship enhances MEMP’s ability to generate consistent returns on its oil and natural gas properties, provides us with a growing source of cash flow from our partnership interests in MEMP and allows us to monetize producing non-core properties. Since MEMP’s initial public offering, we have consummated “drop-down” transactions with MEMP totaling approximately $376 million. In addition, we may have the opportunity to work jointly with MEMP to pursue certain acquisitions of oil and natural gas properties that may not otherwise be attractive acquisition candidates for either of us individually. While we believe that MEMP would be a preferred acquirer of our mature, non-core assets, we are under no obligation to offer to sell, and it is under no obligation to offer to buy, any of our properties.

 

Financial strength and flexibility.    During 2013, we generated $159 million of pro forma MRD Segment Adjusted EBITDA and made pro forma total capital expenditures of $203 million. During the six months ended June 30, 2014, we generated pro forma MRD Segment Adjusted EBITDA of $163 million and made pro forma capital expenditures of $166 million. We intend to continue to fund our organic growth predominantly with internally generated cash flows while maintaining ample liquidity for opportunistic acquisitions. We will continue to maintain a disciplined approach to spending whereby we allocate capital in order to optimize returns and create shareholder value. We seek to protect these future cash flows and liquidity levels by maintaining a three-to-five year rolling hedge program. As of June 30, 2014, our total liquidity, consisting of cash on hand and available borrowing capacity under our revolving credit facility, was approximately $121.6 million.

 

Initial Public Offering and Recent Developments

 

On June 18, 2014, we completed our initial public offering of 49,220,000 shares of common stock at a price to the public of $19.00 per share. Of the 49,220,000 shares offered, 21,500,000 were offered by us and 27,720,000 were offered by the selling stockholder, MRD Holdco. We did not receive any proceeds from the sale of shares by MRD Holdco. We used the net proceeds of approximately $380.7 million from our sale of shares in our initial public offering (i) to redeem the 10.00%/10.75% Senior PIK toggle notes due 2018 (the “PIK notes”) issued by MRD LLC in their entirety and to pay the applicable premium in connection with such redemption and accrued and unpaid interest to the date of redemption, (ii) together with borrowings of approximately $614.5 million under our $2.0 billion revolving credit facility entered into in connection with the closing of our initial public offering, to make a cash payment to certain former management members of WildHorse Resources in connection with their contribution to us of their membership interests and incentive units in WildHorse Resources, (iii) to repay borrowings outstanding under WildHorse Resources’ revolving credit facility and second lien term loan, which we refer to collectively as WildHorse Resources’ credit agreements, (iv) to reimburse MRD LLC for interest paid on the PIK notes and (v) to pay costs associated with our revolving credit facility.

 

On July 10, 2014, we completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes accrues from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The net proceeds of approximately $586.0 million, after deducting the initial purchasers’ discounts and commissions and offering expenses, were used to repay a portion of the borrowings outstanding under our revolving credit facility. The amounts to be repaid under our revolving credit facility were incurred to repay the amounts outstanding under WildHorse Resources’ credit facilities in connection with the closing of our initial public offering. In conjunction with the closing of the offer and sale of the MRD Senior Notes, the borrowing base under our revolving credit facility was automatically decreased by $56.5 million.

 

 

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Acquisition History

 

We built out our leasehold positions in North Louisiana, East Texas and the Rocky Mountains primarily through the following acquisition activities:

 

   

In November 2007, we acquired interests in the Joaquin Field, which is the core of our East Texas acreage;

 

   

In December 2007, we acquired interests in the Tepee Field in the Piceance Basin in Colorado;

 

   

In April and May 2010, we acquired interests in the Terryville Complex and other North Louisiana fields, which are the core of our North Louisiana acreage;

 

   

In November 2010, we acquired interests in the Spider and E. Logansport Fields in North Louisiana;

 

   

In May 2012, we acquired interests in the Terryville Complex and Double A Field in North Louisiana and East Texas;

 

   

In April 2013, we acquired interests in the West Simsboro and Simsboro Fields of the Terryville Complex in North Louisiana;

 

   

In November 2013, we acquired the remaining equity interests in Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C. and Black Diamond Minerals, LLC, which hold oil and natural gas properties in East Texas, North Louisiana and the Rocky Mountains; and

 

   

In February 2014, we repurchased net profits interests in the Terryville Complex from an affiliate of NGP for $63.4 million after customary adjustments. These net profits interests were originally sold to the NGP affiliate upon the completion of certain acquisitions in 2010 by WildHorse Resources.

 

Our Principal Stockholder

 

Our principal stockholder is MRD Holdco, which is controlled by the Funds, which are three of the private equity funds managed by NGP. Upon completion of this offering, MRD Holdco, one of the selling stockholders in this offering, will own approximately 41% of our common stock (or approximately 39% if the underwriters’ option to purchase additional shares from the selling stockholders is exercised in full). Pursuant to a voting agreement, MRD Holdco also has the right to direct the vote of an additional approximately 19% of our common stock (or approximately 18% if the underwriters’ option to purchase additional shares from the selling stockholders is exercised in full) owned by certain former management members of WildHorse Resources (including the other selling stockholders). The Funds also collectively indirectly own 50% of MEMP’s incentive distribution rights, and MRD Holdco owns 5,360,912 subordinated units of MEMP, representing an approximate 6.2% limited partner interest in MEMP. We are also a party to certain other agreements with MRD Holdco, the Funds and certain of their affiliates. For a description of the voting agreement and these other agreements, please read “Certain Relationships and Related Party Transactions.”

 

Founded in 1988, NGP is a family of private equity investment funds, with cumulative committed capital of approximately $10.5 billion since inception, organized to make investments in the natural resources sector. NGP is part of the investment platform of NGP Energy Capital Management, a premier investment franchise in the natural resources industry, which together with its affiliates has managed approximately $13 billion in cumulative committed capital since inception.

 

Our Interest in Memorial Production Partners LP

 

Through our ownership of its general partner, we control MEMP. We also own 50% of its incentive distribution rights. MEMP is a publicly traded limited partnership engaged in the acquisition, exploitation,

 

 

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development and production of oil and natural gas properties in the United States, with assets consisting primarily of producing oil and natural gas properties that are located in East Texas/North Louisiana, the Rockies, South Texas, the Permian and offshore southern California. Most of MEMP’s properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. Because we control MEMP, we are required to consolidate MEMP for accounting and financial reporting purposes, even though we and MEMP have independent capital structures.

 

During each of the year ended December 31, 2013 and six months ended June 30, 2014, less than $0.1 million of distributions were made in respect of the MEMP incentive distribution rights. Please see “Business—Relationship with Memorial Production Partners LP” for further information on our interest in MEMP.

 

Risk Factors

 

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, please read “Risk Factors” beginning on page 22 of this prospectus and “Cautionary Note Regarding Forward-Looking Statements.”

 

Corporate History and Structure

 

We are a Delaware corporation formed by MRD LLC in January 2014 engaged in the acquisition, exploitation, and development of natural gas, NGL and oil properties primarily in North Louisiana and East Texas. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by the Funds to own, acquire, exploit and develop oil and natural gas properties.

 

We completed our initial public offering on June 18, 2014. In connection with the closing of our initial public offering, MRD LLC contributed to us substantially all of its assets, comprised of the following, in exchange for shares of our common stock (which were distributed to MRD LLC’s sole member, MRD Holdco): (1) 100% of its ownership interests in Classic Hydrocarbons Holdings, L.P. (“Classic”), Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”), Black Diamond Minerals, LLC (“Black Diamond”), Beta Operating Company, LLC (“Beta Operating”), MRD Operating LLC (“MRD Operating”) and MEMP GP, which owns a 0.1% general partner interest and 50% of the incentive distribution rights in MEMP, and (2) its 99.9% membership interest in WildHorse Resources. In addition, certain former management members of WildHorse Resources contributed to us the remaining 0.1% membership interest in WildHorse Resources, and also exchanged their incentive units in WildHorse Resources, for shares of our common stock and cash consideration. As a result, we are majority-owned by the group consisting of MRD Holdco and certain former management members of WildHorse Resources.

 

Following the completion of our initial public offering, MRD LLC distributed to MRD Holdco (i) its interests in BlueStone, MRD Royalty LLC, MRD Midstream, Golden Energy Partners LLC (“Golden Energy”) and Classic Pipeline; (ii) the MEMP subordinated units; (iii) the remaining cash released from its debt service reserve account in connection with the redemption of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014. We also reimbursed MRD LLC for the approximately $17.2 million interest payment that it made on the PIK notes on June 15, 2014, which was distributed to MRD Holdco.

 

As part of the restructuring transactions, we merged Black Diamond into MRD Operating, and MRD LLC was merged into MRD Operating upon the termination of the PIK notes indenture on June 27, 2014.

 

 

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For more information regarding BlueStone, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—MRD Segment.” For more information about the services agreement with WildHorse Resources, see “Certain Relationships and Related Party Transactions—Services Agreement.”

 

The following diagram shows our ownership structure after giving effect to this offering, assuming no exercise of the underwriters’ option to purchase additional shares from the selling stockholders, and does not give effect to 19,250,000 shares of common stock reserved for future issuance under the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (described in “Management—2014 Long Term Incentive Plan”). See “Principal and Selling Stockholders” for the number of shares being offered by MRD Holdco and the other selling stockholders, respectively.

 

LOGO

 

(1)   If the underwriters exercise in full their option to purchase additional shares of common stock from the selling stockholders, the ownership interest of the public stockholders will increase to 81,188,124 shares of common stock, representing an aggregate 42% ownership interest in us, MRD Holdco will own 76,227,141 shares of common stock, representing an aggregate 39% ownership interest in us and certain former management members of WildHorse Resources will own 35,084,735 shares of common stock, representing an aggregate 18% ownership interest in us.
(2)   As of September 30, 2014.

 

 

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(3)   “The Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively own all of the membership interests in MRD Holdco. Please read “Principal and Selling Stockholders” for information regarding beneficial ownership. The Funds collectively indirectly own 50% of the Partnership’s incentive distribution rights.
(4)   Subsidiaries of MRD Holdco include BlueStone, MRD Royalty, MRD Midstream, Golden Energy and Classic Pipeline. Also, please see the “Principal and Selling Stockholders” table on page 145 for the beneficial ownership of our shares by our executive officers and directors.
(5)   Includes Classic, Classic GP and Beta Operating.

 

Corporate Information

 

Our principal executive offices are located at 1301 McKinney St., Suite 2100, Houston, Texas 77010, and our phone number is (713) 588-8300. Our website address is www.memorialrd.com. We make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

 

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 other public companies that are not emerging growth companies, we are not 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 of the Sarbanes-Oxley Act of 2002;

 

   

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, or 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;

 

   

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

 

   

obtain shareholder 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, or the Securities Act, for complying with new or revised accounting standards, but we have irrevocably opted out of the

 

 

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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.

 

The Offering

 

Selling Stockholders

MRD Holdco and certain former management members of WildHorse Resources.

 

Common stock offered by the selling stockholders

27,798,368 shares (or 31,968,125 shares, if the underwriters exercise in full their option to purchase additional shares).

 

Common stock to be outstanding immediately after the offering

193,559,211 shares. The number of shares of common stock outstanding will not change as a result of this offering.

 

Option to purchase additional shares

The selling stockholders have granted the underwriters a 30-day option to purchase up to an aggregate of 4,169,757 additional shares of our common stock held by the selling stockholders to cover over-allotments.

 

Common stock voting rights

Each share of our common stock entitles its holder to one vote.

 

Use of proceeds

We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders, including pursuant to any exercise by the underwriters of their option to purchase additional shares of our common stock. The selling stockholders may be deemed under federal securities laws to be underwriters with respect to the common stock they may sell in connection with this offering.

 

Dividend policy

We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our board of directors (our “Board”) in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements and other contracts and other factors our Board deems relevant. See “Dividend Policy.”

 

Risk factors

You should carefully read and consider the information set forth under “Risk Factors” beginning on page 22 of this prospectus and all other information set forth in this prospectus before deciding to invest in our common stock.

 

Listing and trading symbol

Our common stock is listed on the NASDAQ Global Select Market (“NASDAQ”) under the trading symbol “MRD.”

 

Summary Historical Consolidated and Combined Pro Forma Financial Data

 

Prior to the restructuring transactions and the closing of our initial public offering, MRD LLC and its consolidated subsidiaries, our accounting predecessor, controlled MEMP through its ownership of MEMP GP,

 

 

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the general partner of MEMP. Because MRD LLC controlled MEMP through its ownership of the general partner, MRD LLC was required to consolidate MEMP for accounting and financial reporting purposes even though MRD LLC owned a minority of its partner interests and MRD LLC and MEMP had independent capital structures. MRD LLC received cash distributions from MEMP as a result of its partner interests and incentive distribution rights in MEMP, when declared and paid by MEMP. In connection with the closing of our initial public offering, MRD LLC contributed substantially all of its existing assets to us in exchange for shares of our common stock. Through our ownership of MEMP GP, we continue to control MEMP and therefore will continue to consolidate the results of MEMP into our consolidated financial statements in future periods.

 

Our predecessor had two reportable business segments, both of which were engaged in the acquisition, exploitation, development and production of oil and natural gas properties:

 

   

MRD—reflected all of MRD LLC’s consolidating subsidiaries except for MEMP and its subsidiaries.

 

   

MEMP—reflected the consolidated and combined operations of MEMP and its subsidiaries.

 

We continue to have two reportable segments. For more information regarding reportable business segments, please see the predecessor’s audited historical financial statements and related notes and our unaudited historical interim financial statements included elsewhere in this prospectus.

 

The following tables include summary historical financial data for us and our predecessor, as well as the MRD Segment as of and for the periods indicated. The summary historical financial data of our predecessor as of and for the years ended December 31, 2013 and 2012 were derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The summary historical financial data as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 were derived from our unaudited interim financial statements included elsewhere in this prospectus. The summary historical financial data of the MRD Segment as of and for the years ended December 31, 2013 and 2012 were derived from certain financial information used in the preparation of our predecessor’s audited financial statements. The summary historical financial data for the MRD Segment as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 were derived from certain financial information used in the preparation of our unaudited interim financial statements.

 

The summary unaudited pro forma data as of June 30, 2014 has been prepared to give pro forma effect to MEMP’s July 2014 acquisition of certain oil and natural gas liquids properties in Wyoming (the “MEMP Wyoming Acquisition”), MEMP’s July and September 2014 equity offerings (the “MEMP Offerings”) and our private placement on July 10, 2014 of $600.0 million aggregate principal amount of 5.875% senior unsecured notes at par as well as MEMP’s private placement on July 17, 2014 of $500.0 million aggregate principal amount of 6.875% senior unsecured notes at 98.485% of par (collectively referred to as the “Debt Offerings”).

 

The summary unaudited pro forma data for the six months ended June 30, 2014 and for the year ended December 31, 2013 has been prepared to give pro forma effect to: (i) the exclusion of both BlueStone and Classic Pipeline as well as the MEMP subordinated units, none of which were conveyed to us in connection with our initial public offering; (ii) certain restructuring transactions that took place in connection with our initial public offering; (iii) the MEMP Wyoming Acquisition and the MEMP Offerings; (iv) the Debt Offerings; and (v) incremental federal income tax expense.

 

We derived the data in the following tables from, and the following tables should be read together with and is qualified in its entirety by reference to, our historical financial statements (including those of our predecessor) and our pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our pro forma and historical consolidated financial statements, all included elsewhere in this prospectus. Among

 

 

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other things, those historical consolidated and combined financial statements and pro forma financial statements include more detailed information regarding the basis of presentation for the following data.

 

           Memorial Resource Development
Corp. Pro Forma
 
     Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended June 30,
 
     2013     2012     2014     2013     2013     2014  
     (Predecessor)           (Predecessor)        
                 (unaudited)     (unaudited)  
     (in thousands)  

Statement of Operations Data:

            

Revenues:

            

Oil and natural gas sales

   $ 571,948      $ 393,631      $ 425,140      $ 268,095      $ 740,221      $ 514,650   

Other revenues

     3,075        3,237        2,252        1,131        2,268        1,702   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     575,023        396,868        427,392        269,226        742,489        516,352   

Costs and expenses:

            

Lease operating

     113,640        103,754        65,676        52,351        165,092        90,350   

Pipeline operating

     1,835        2,114        1,165        949        1,835        1,165   

Exploration

     2,356        9,800        1,290        973        2,356        1,290   

Production and ad valorem taxes

     27,146        23,624        19,583        16,056        53,079        31,475   

Depreciation, depletion and amortization

     184,717        138,672        131,459        87,192        233,244        159,910   

Impairment of proved oil and gas properties

     6,600        28,871        —          —          4,201        —     

Incentive unit compensation expense

     —          —          943,840        —          —          943,840   

General and administrative

     125,358        69,187        39,865        36,336        101,098        38,826   

Accretion of asset retirement obligations

     5,581        5,009        3,048        2,662        5,803        3,188   

(Gain) loss on commodity derivatives

     (29,294     (34,905     201,072        (31,584     (29,311     201,072   

(Gain) loss on sale of property

     (85,621     (9,761     3,057        3,845        3,927        3,167   

Other, net

     649        502        (12     598        649        (12
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     352,967        336,867        1,410,043        169,378        541,973        1,474,271   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     222,056        60,001        (982,651     99,848        200,516        (957,919
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

            

Interest expense, net

     (69,250     (33,238     (68,583     (21,379     (117,843     (70,015

Loss on extinguishment of debt

     —          —          (37,248     —          —          (37,248

Amortization of investment premium

     —          (194     —          —          —          —     

Other, net

     145        535        87        57        143        87   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (69,105     (32,897     (105,744     (21,322     (117,700     (107,176

Income tax benefit (expense)

     (1,619     (107     11,436        (188     (29,814     3,048   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 151,332      $ 26,997      $ (1,076,959   $ 78,338      $ 53,002      $ (1,062,047
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data:

            

Net cash provided by operating activities

   $ 277,823      $ 240,404      $ 177,747      $ 163,142       

Net cash used in investing activities

     367,443        606,738        483,736        201,129       

Net cash provided by financing activities

     117,950        361,761        244,234        59,687       

Balance Sheet Data (at period end):

            

Working capital (deficit)

   $ 48,256      $ 63,054      $ (60,022       $ (65,614

Total assets

     2,829,161        2,459,304        3,043,920            3,921,945   

Total debt

     1,663,217        939,382        1,767,806            2,096,112   

Total equity (including noncontrolling interests)

     858,132        1,276,709        816,652            1,357,280   

 

 

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     MRD Segment     MRD Segment
Pro Forma
 
     Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended June 30,
 
     2013     2012     2014     2013     2013     2014  
                 (unaudited)     (unaudited)  
     (in thousands)  

Statement of Operations Data:

            

Revenues:

            

Oil and natural gas sales

   $ 230,751      $ 138,032      $ 202,594      $ 110,834      $ 212,603      $ 200,905   

Other revenues

     807        782        556        233        —          6   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     231,558        138,814        203,150        110,067        212,603        200,911   

Costs and expenses:

            

Lease operating

     25,006        24,438        11,666        10,921        23,354        11,732   

Exploration

     1,226        7,337        1,080        698        1,226        1,080   

Production and ad valorem taxes

     9,362        7,576        6,923        7,209        8,485        6,872   

Depreciation, depletion and amortization

     87,043        62,636        67,946        42,129        76,524        67,203   

Impairment of proved oil and gas properties

     2,527        18,339        —          —          128        —     

Incentive unit compensation expense

     —          —          943,840        —          —          943,840   

General and administrative

     81,758        38,414        19,319        14,813        57,498        18,280   

Accretion of asset retirement obligations

     728        632        325        369        670        325   

(Gain) loss on commodity derivatives

     (3,013     (13,488     15,960        (8,574     (3,030     15,960   

(Gain) loss on sale of property

     (82,773     (2     3,057        6,713        6,775        3,167   

Other, net

     2        364        —          (25     2        —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     121,866        146,246        1,070,116        74,253        171,632        1,068,459   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     109,692        (7,432     (866,966     36,814        40,971        (867,548
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

            

Interest expense, net

     (27,349     (12,802     (34,469     (6,906     (45,972     (21,428

Loss on extinguishment of debt

     —          —          (37,248     —          —          (37,248

Earnings from equity investments

     1,066        4,880        (12,930     10,814        269        (68

Other, net

     145        535        87        32        143        87   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (26,138     (7,387     (84,560     3,940        (45,560     (58,657

Income tax (expense) benefit

     (1,311     178        11,511        —          1,652        2,395   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 82,243      $ (14,641   $ (940,015   $ 40,754      $ (2,937   $ (923,810
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data (Unaudited):

            

Net cash provided by operating activities

   $ 83,910      $ 84,172      $ 81,695      $ 81,266       

Net cash used in investing activities

     5,533        230,471        114,883        94,983       

Net cash provided by (used in) financing activities

     (38,963     133,271        (15,777     38,789       

Other Financial Data:

            

Adjusted EBITDA (unaudited)

   $ 197,903      $ 132,105      $ 163,947      $ 96,843      $ 159,239      $ 162,732   

Balance Sheet Data (at period end):

            

Working capital (unaudited)

   $ 51,214      $ 2,424      $ 10,328          $ 10,328   

Total assets

     1,281,134        1,102,406        1,143,635            1,158,191   

Total debt

     871,150        309,200        619,000            633,000   

Total equity (unaudited)

     279,412        682,644        399,957            400,513   

 

Adjusted EBITDA

 

Our reportable business segments are organized in a manner that reflects how management manages those business activities.

 

We evaluate segment performance based on Adjusted EBITDA. The definition and calculation of Adjusted EBITDA and the reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) is included in the notes to our and our predecessor’s consolidated and combined financial statements found elsewhere in this prospectus.

 

 

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Adjusted EBITDA (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our management in evaluating segment performance. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

 

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss). Our computation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements. The following table provides a reconciliation of our pro forma MRD Segment net income to our pro forma MRD Segment Adjusted EBITDA.

 

Calculation of Adjusted EBITDA—MRD Segment Pro Forma

 

     Year Ended
December 31,
2013
    Six Months
Ended June 30,
2014
 

Net income (loss)

   $ (2,937   $ (923,810

Interest expense, net

     45,972        21,428   

Loss on extinguishment of debt

     —          37,248   

Income tax expense (benefit)

     (1,652     (2,395

Depreciation, depletion and amortization

     76,524        67,203   

Impairment of proved oil and gas properties

     128        —     

Accretion of AROs

     670        325   

(Gain) loss on commodity derivative instruments

     (3,030     15,960   

Cash settlements received (paid) on commodity derivative instruments

     12,257        (8,629

(Gain) loss on sale of properties

     6,775        3,167   

Acquisition related costs

     1,584        1,068   

Incentive unit-based compensation expense

     22,635        944,015   

Exploration costs

     1,226        1,080   

Non-cash equity (income) loss from MEMP

     (1,050     68   

Cash distributions from MEMP

     137        6,004   
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 159,239      $ 162,732   
  

 

 

   

 

 

 

 

Summary Reserve, Production and Operating Data for the MRD Segment

 

The following tables present summary data with respect to the estimated historical net proved oil and natural gas reserves and production and operating data for the MRD Segment as of the dates presented.

 

The proved reserve estimates presented in the table below were prepared by NSAI, and the probable and possible reserve estimates were prepared by our management and audited by NSAI. Regarding our properties, estimates comprising 100% of the total proved reserves in our reserve report were prepared by NSAI. These reserve estimates were prepared in accordance with current SEC rules regarding oil and natural gas reserve reporting. The following tables also contain certain summary information regarding production and sales of oil and natural gas with respect to such properties.

 

Please read “Business—Our Operations” as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the summaries of our reserve report included herein as Appendices B-1 and B-2 in evaluating the material presented below.

 

 

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Reserve Data

 

Estimated Proved Reserves

   As of
December 31,
2013
 

Natural gas (MMcf)

     802,254   

Oil/Condensate (MBbls)

     11,311   

NGLs (MBbls)

     42,577   
  

 

 

 

Total estimated net proved reserves (MMcfe)

     1,125,577   
  

 

 

 

Proved developed producing (MMcfe)

     323,351   

Proved developed non-producing (MMcfe)

     44,290   

Proved undeveloped (MMcfe)

     757,936   

Proved developed reserves as a percentage of total proved reserves

     33

PV-10 of proved reserves (in millions)(1)

   $ 1,469   

Estimated Probable Reserves(2)

      

Natural Gas (MMcf)

     535,185   

Oil/Condensate (MBbls)

     10,480   

NGLs (MBbls)

     33,709   
  

 

 

 

Total estimated net probable reserves (MMcfe)

     800,317   
  

 

 

 

PV-10 of probable reserves (in millions)(1)

   $ 1,052   

Estimated Possible Reserves(2)

      

Natural Gas (MMcf)

     1,080,539   

Oil/Condensate (MBbls)

     36,376   

NGLs (MBbls)

     68,686   
  

 

 

 

Total estimated net possible reserves (MMcfe)

     1,710,913   
  

 

 

 

PV-10 of possible reserves (in millions)(1)

   $ 2,386   

 

(1)   PV-10 is a non-GAAP financial measure and differs from standardized measure, the most directly comparable GAAP financial measure. Please see “—Reserves.”
(2)   Substantially all of our estimated probable and possible reserves are classified as undeveloped.

 

 

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Production and Operating Data

 

     Historical MRD Segment(1)      MRD Segment Pro Forma  
     Year Ended
December 31,
     Six Months Ended
June 30,
     Year Ended
December 31,
     Six Months Ended
June 30,
 
     2013      2012      2014      2013      2013      2014  

Production and operating data:

                 

Oil (MBbls)

     665         369         479         345         523         467   

NGLs (MBbls)

     1,457         898         1,024         552         1,454         1,024   

Natural gas (MMcf)

     34,092         24,130         26,346         16,173         33,205         26,346   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (MMcfe)

     46,819         31,731         35,367         21,554         45,066         35,297   

Average net production
(MMcfe/d)

     128.3         86.7         195.4         119.1         123.5         195.0   

Average sales price:

                 

Oil (per Bbl)

   $ 100.76       $ 95.56       $ 96.57       $ 99.28       $ 100.15       $ 96.59   

NGLs (per Bbl)

     36.99         40.78         44.37         37.25         36.93         44.37   

Natural gas (per Mcf)

     3.22         2.74         4.21         3.47         3.21         4.21   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Average price per Mcfe

   $ 4.93       $ 4.35       $ 5.73       $ 5.14       $ 4.73       $ 5.73   

Average unit costs per Mcfe:

                 

Lease operating expenses

   $ 0.53       $ 0.77       $ 0.33       $ 0.51       $ 0.52       $ 0.33   

Production and ad valorem taxes

   $ 0.20       $ 0.24       $ 0.20       $ 0.33       $ 0.19       $ 0.20   

General and administrative(2)

   $ 1.75       $ 1.21       $ 0.55       $ 0.69       $ 1.27       $ 0.55   

Depletion, depreciation and amortization

   $ 1.86       $ 1.97       $ 1.92       $ 1.95       $ 1.69       $ 1.90   

 

(1)   Includes production and operating data for BlueStone, Golden Energy and Classic Pipeline, which were not contributed to us in connection with our initial public offering. The MRD Segment Pro Forma production and operating data has been adjusted to exclude the production and operating data for BlueStone and Classic Pipeline.
(2)   Includes $0.92 and $0.30 per Mcfe of incentive unit compensation expense for the historical MRD Segment for the years ended December 31, 2013 and 2012. The pro forma general and administrative expense for the year ended December 31, 2013 includes $0.50 per Mcfe of incentive unit compensation expense.

 

 

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RISK FACTORS

 

Investing in our common stock involves a high degree of risk. You should carefully consider the risks and uncertainties described below, as well as other information contained in this prospectus, before investing in our common stock. If any of the following risks actually occur, our business, financial condition, operating results or cash flow could be materially and adversely affected.

 

Risks Related to Our Business

 

Oil, natural gas and NGL prices are volatile, due to factors beyond our control, and will greatly affect our business, results of operations, liquidity and financial condition.

 

Our revenues, operating results, profitability, liquidity, future growth and the value of our properties depend primarily on prevailing commodity prices. Historically, oil and natural gas prices have been volatile and fluctuate in response to changes in supply and demand, market uncertainty, and other factors that are beyond our control, including:

 

   

the regional, domestic and foreign supply of oil, natural gas and NGLs;

 

   

the level of commodity prices and expectations about future commodity prices;

 

   

the level of global oil and natural gas exploration and production;

 

   

localized supply and demand fundamentals, including the proximity and capacity of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

 

   

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

 

   

the price and quantity of foreign imports;

 

   

political and economic conditions in oil producing countries;

 

   

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

   

speculative trading in crude oil and natural gas derivative contracts;

 

   

the level of consumer product demand;

 

   

weather conditions and other natural disasters;

 

   

risks associated with operating drilling rigs;

 

   

technological advances affecting exploration and production operations and overall energy consumption;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the continued threat of terrorism and the impact of military and other action;

 

   

the price and availability of competitors’ supplies of oil and natural gas and alternative fuels; and

 

   

overall domestic and global economic conditions.

 

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For example, for the five years ended December 31, 2013, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $33.98 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $7.50 per MMBtu to a low of $1.82 per MMBtu. Any substantial decline in commodity prices will likely have a material adverse effect on our operations and financial condition, as well as on our level of expenditures for the development of our reserves.

 

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NGLs comprised 23% of our estimated proved reserves at December 31, 2013 and accounted for 17% of our production on a volume equivalent basis for the six months ended June 30, 2014. Realized NGL prices have decreased recently principally due to significant supply. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. A further or extended decline in NGL prices could materially and adversely affect our future business, financial condition and results of operations.

 

The prices that we receive for our oil and natural gas production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX or ICE, that are used for calculating hedge positions. The prices we receive for our production are also affected by the specific characteristics of the production relative to production sold at benchmark prices. These discounts, if significant, could adversely affect our results of operations and financial condition.

 

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

 

As a recently formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. Pursuant to a services agreement entered into in connection with our initial public offering, we depend on the services of an entity managed by certain former management members of WildHorse Resources for supervising and managing our drilling operations in the Terryville Complex. See “Certain Relationships and Related Party Transactions—Services Agreement.” Under certain circumstances, this agreement may be terminated by the parties thereto and we may be unable to find replacement services, which could materially and adversely affect our ability to execute our plans for the development of the Terryville Complex. In addition, the failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

 

Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our business, results of operations, liquidity and financial condition.

 

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and financial condition are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which would adversely affect our business, financial condition and results of operations.

 

If commodity prices decline, a significant portion of our development projects may become uneconomic and cause write downs of the value of our oil and natural gas properties, which may adversely affect our financial condition and liquidity.

 

Significantly lower oil prices, or sustained lower natural gas prices, would render many of our development and production projects uneconomic and result in a reduction of our estimated reserves, which would reduce the borrowing base under our revolving credit facility and our ability to finance planned or desired capital expenditures or acquisitions.

 

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Deteriorating commodity prices may cause us to recognize impairments in the value of our properties. In addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

 

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.

 

Our drilling activities are subject to many risks. For example, we cannot assure you that wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then-realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

   

unusual or unexpected geological formations;

 

   

loss of drilling fluid circulation;

 

   

loss of well control;

 

   

title problems;

 

   

facility or equipment malfunctions;

 

   

unexpected operational events;

 

   

shortages or delivery delays or increases in the cost of equipment and services;

 

   

reductions in oil, natural gas and NGL prices;

 

   

lack of proximity to and shortage of capacity of transportation facilities;

 

   

the limited availability of financing at acceptable rates;

 

   

delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases; and

 

   

adverse weather conditions.

 

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

 

Part of our strategy involves using 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. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

 

   

landing our wellbore in the desired drilling zone;

 

   

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

 

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running our casing the entire length of the wellbore; and

 

   

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

 

Risks that we face while completing our wells include, but are not limited to, 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.

 

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.

 

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

 

We own a significant amount of unproved property, which we expect to further our development efforts. We intend to continue to undertake acquisitions of unproved properties in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

 

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

 

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2013, we had 10,825 gross (6,985 net) acres scheduled to expire in 2014, 20,078 gross (12,015 net) acres scheduled to expire in 2015, 31,215 gross (20,875 net) acres scheduled to expire in 2016 and 28,228 gross (19,649 net) acres scheduled to expire in 2017. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Moreover, many of our leases require lessor consent to pool, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases scheduled to expire in 2014 and 2015, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs when needed, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset base, cash flows 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 can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

 

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Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

 

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. At December 31, 2013, 10 gross (9.4 net) wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. From January 2011 through December 31, 2013, we have drilled 83 gross (51.9 net) wells and, out of these wells, 3 gross (1.5 net) wells were dry holes.

 

Our identified drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

As of December 31, 2013, we had identified 1,582 gross (1,091 net) horizontal drilling locations on our existing acreage. Only 145 of these gross identified drilling locations had proved undeveloped reserves attributed to them in our reserve report. These drilling locations, including those with attributed proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory changes and approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure, inclement weather, and lease expirations.

 

Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional analysis of data. We cannot predict in advance of drilling and testing whether any particular drilling location will yield production in sufficient quantities to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in our areas of operations may not be indicative of future or long-term production rates.

 

A majority of our 1,431 gross horizontal drilling locations (as of December 31, 2013) within the Terryville Complex are identified within four distinct zones, with such gross horizontal drilling locations being roughly evenly distributed amongst such four zones. To date, we have drilled 31 horizontal wells within the key formations in Terryville Complex. Accordingly, we have limited experience in drilling horizontal wells in the zones of the Terryville Complex to which we have ascribed a substantial majority of our gross identified drilling locations. Please see “Business—Our Operations—Drilling Locations” for more information on our gross identified drilling locations.

 

Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas reserves from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial condition and results of operations.

 

We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. Our ability to drill, recomplete and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, and drilling results. Because of these

 

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uncertainties, we cannot be certain of the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition and results of operations.

 

The development of our proved undeveloped and unproved reserves may take longer and may require higher levels of capital expenditures than we anticipate and may not be economically viable.

 

Approximately 67% of our total proved reserves at December 31, 2013 were proved undeveloped reserves; those reserves may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves. The reserve data included in our reserve report assumes that substantial capital expenditures are required to develop such undeveloped reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce future net revenues of our estimated proved undeveloped 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 proved reserves as proved undeveloped reserves.

 

Our acquisition and development operations require substantial capital expenditures.

 

The development and production of our oil and natural gas reserves requires substantial capital expenditures. If our revenues decrease, as a result of lower oil or natural gas prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations at our current level. In addition, our ability to acquire additional properties will be adversely affected if we are unable to fund such acquisitions from cash flow from operations or other sources.

 

Shortages of rigs, equipment and crews could delay our operations, increase our costs and delay forecasted revenue.

 

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and thus the results of our operations.

 

Our hedging strategy may not effectively mitigate the impact of commodity price volatility from our cash flows, and our hedging activities could result in cash losses and may limit potential gains.

 

We intend to maintain a portfolio of commodity derivative contracts. These commodity derivative contracts include natural gas, oil and NGL financial swaps and collar contracts and natural gas basis financial swaps. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. In addition, our revolving credit facility limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. If our actual production and sales for any period are less than our hedged production

 

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and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

 

Our hedging transactions expose us to counterparty credit risk.

 

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets or other unforeseen events could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract and, accordingly, prevent us from realizing the benefit of the derivative contract.

 

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

 

The process of estimating natural gas and oil 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 our estimated quantities and present value of our reserves.

 

In order to prepare our 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 natural gas prices, oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

 

Actual future production, oil prices, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

 

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

 

Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

 

SEC rules could limit our ability to book additional PUDs in the future.

 

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. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

 

The PV-10 of our estimated proved, probable and possible reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.

 

The present value of future net cash flows from our proved, probable and possible reserves shown in this report, or PV-10, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (“FASB”), we base the

 

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estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

 

Our producing properties are concentrated in North Louisiana and East Texas, making us vulnerable to risks associated with operating in one major geographic area.

 

Our producing properties are geographically concentrated in North Louisiana and East Texas. At December 31, 2013, 99% of our total estimated proved reserves and for the six months ended June 30, 2014, 97% of our net average daily production were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

 

Expenses not covered by our insurance could have a material adverse effect on our financial position, results of operations and cash flows.

 

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including natural disasters, the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The location of any properties and other assets near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations, substantial revenue losses and repairs to resume operations.

 

We maintain insurance coverage against potential losses that we believe is customary in the industry. However, these policies may not cover all liabilities, claims, fines, penalties or costs and expenses that we may incur in connection with our business and operations, including those related to environmental claims. Pollution and environmental risks generally are not fully insurable. In addition, we cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

 

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 businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

 

Any acquisition involves potential risks, including, among other things:

 

   

the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs;

 

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the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

   

an inability to obtain satisfactory title to the assets we acquire; and

 

   

potential lack of operating experience in the geographic market where the acquired assets or business are located.

 

The success of any completed acquisition 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.

 

NGP, the Funds and their affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

 

Our governing documents provide that NGP and the Funds and their respective affiliates (including NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, NGP and the Funds and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

 

NGP and the Funds are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations.

 

We may be unable to compete effectively with larger companies.

 

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas, and securing equipment and trained personnel. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis, and many of our competitors have access to capital at a lower cost than that available to us. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

 

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We require substantial capital expenditures to conduct our operations, engage in acquisition activities and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy.

 

We require substantial capital expenditures to conduct our exploration, development and production operations, engage in acquisition activities and replace our production. We have established a capital budget for 2014 of approximately $351 million and we intend to rely on cash flow from operating activities as our primary sources of liquidity. We also may engage in asset and equity sale transactions to, among other things, fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable. There can be no assurance that such sources will be sufficient to fund our exploration, development and acquisition activities. If our revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, however, and we are unable to obtain additional equity or debt financing in the capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to replace our reserves or maintain our production levels.

 

Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production.

 

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business.

 

Our use of 2-D and 3-D 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, 2-D and 3-D 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. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

 

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

 

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

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our natural gas and oil exploration, production, and transportation operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local

 

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governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, and results of operations.

 

Our oil and natural gas development and production operations are also 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 before conducting regulated drilling 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, or the 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, 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 addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. 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. 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.

 

Please read “Business—Regulation of Environmental and Occupational Health and Safety Matters” for a further description of the laws and regulations that affect us.

 

Climate change legislation or regulations restricting emissions of “greenhouse gases,” or GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

 

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”), including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act (“CAA”) that establish Prevention of Significant Deterioration, or PSD, and Title V permit reviews for GHG emissions

 

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from certain large stationary sources. On June 23, 2014, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD or Title V programs. The EPA has announced that it is currently evaluating the decision and awaiting further action by the courts, and that it will provide relevant guidance on GHG permitting requirements.

 

The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources on an annual basis in the United States, including, among others, certain oil and natural gas production facilities, which includes certain of our operations. The adoption and implementation of any 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 or could adversely affect demand for the oil and natural gas we produce. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

 

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 that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the Obama administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, possibly including further restrictions on emissions of methane from oil and gas operations.

 

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 that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Please read “Business—Regulation of Environmental and Occupational Health and Safety Matters” for a further description of the laws and regulations that affect us.

 

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions, loss of leasehold or delays on our operations, which could adversely affect our results of operations and financial condition.

 

The federal Endangered Species Act (“ESA”) and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. For instance, the American burying beetle and the lesser prairie chicken both have habitat in some areas where we operate. The U.S. Fish and Wildlife Service (“FWS”) identified the lesser prairie chicken, which inhabits portions of Colorado, Kansas, Nebraska, New Mexico, Oklahoma and Texas, as candidate for listing in 1998 and has listed it as “threatened” in March 2014. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, pursuant to

 

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which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The threatened species status of the lesser prairie chicken is currently subject to a pending lawsuit by at least three states. The lawsuit challenges FWS’ recent classification of the lesser prairie chicken. The presence of protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.

 

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

 

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

 

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

 

The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, or CFTC, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC has issued a large number of rules to implement the Dodd-Frank Act, including a rule establishing an “end-user” exception to mandatory clearing, referred to herein as the “End-User Exception,” and a rule imposing position limits, referred to herein as the Initial Position Limit Rule. The Initial Position Limit Rule was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia on September 28, 2012. The CFTC proposed a new version of the Initial Position Limit Rule in November 2013, referred to herein as the “Re-Proposed Position Limit Rule,” with respect to which the comment period has closed but a final rule has not been issued. The CFTC and bank regulators in September 2014 re-proposed rules which would impose margin requirements on uncleared swaps between banks, swap dealers and major swap participants, referred to herein as the “Re-Proposed SD/MSP Margin Rule.”

 

We qualify as a “non-financial entity” for purposes of the End-User Exception and we utilize such exception so our hedging activity is not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End-User Exception and, if the Re-Proposed SD/MSP Margin Rule is adopted, will be subject to such rule and required to post margin in accordance with such rule in connection with their swaps with other banks, swap dealers and major swap participants. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule and the Re-Proposed SD/MSP Margin Rule are ultimately effected, such proposed rules could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect

 

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against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays, and adversely affect our production.

 

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We routinely apply hydraulic fracturing techniques in our drilling and completion programs.

 

While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the Safe Drinking Water Act, or the SDWA, involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Although the EPA is not the permitting authority for the SDWA’s Underground Injection Control Class II programs in Louisiana, Texas, Wyoming, New Mexico, or Colorado, where we or MEMP maintain operational acreage, the EPA is encouraging state programs to review and consider use of such draft guidance. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in late 2014. In addition, in October 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting “flowback,” as well as “produced water.” If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected sometime in 2014. Moreover, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014.

 

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. The rules include NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rules seek to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules could require a number of modifications to our operations including the installation of new equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely to be responsive to some of these requests. On September 23, 2013, the EPA finalized the portion of the rules addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. On July 1, 2014, the EPA announced proposed amendments and clarifications to the NSPS standards. These standards, as well as any future laws and their implementing regulations, may require us to

 

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obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

 

In addition, in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The revised proposed rule would continue to require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. The Bureau of Land Management plans to issue a final rule in 2014.

 

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft report is expected to be released for public comment and review in late 2014. The EPA’s study could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing.

 

Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Certain states, including Texas and Colorado, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, in October 2011, the Louisiana Department of Natural Resources adopted new rules requiring the public disclosure of the composition and volume of fracturing fluids used in hydraulic fracturing operations. Also, in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

 

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

 

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.

 

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water

 

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used in our exploration and production operations, could adversely impact our operations. Moreover, the imposition of new environmental requirements could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The Federal Water Pollution Control Act (the “CWA”) imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Also, the EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

 

We are not the only partners in MEMP, and MEMP’s partnership agreement requires it to distribute all available cash to its partners, including public unitholders.

 

MEMP is a publicly traded limited partnership. We own MEMP GP, the sole general partner of MEMP, and are entitled to 50% of any cash distributed in respect of MEMP’s incentive distribution rights. MRD Holdco owns 5,360,912 subordinated units representing an approximate 6.2% limited partner interest in MEMP. The remainder of the outstanding limited partner interests in MEMP are common units owned by public unitholders. MEMP’s partnership agreement requires it to distribute, on a quarterly basis, 100% of its available cash to its partners. We receive only our proportionate share of cash distributions from MEMP based on our partner interests in it. The remainder of the quarterly cash distributions is distributed, pro rata, to the public unitholders (and, in the case of 50% of the incentive distribution rights, to the Funds).

 

For MEMP, available cash is generally all cash on hand at the end of each quarter, after payment of fees and expenses and the establishment of cash reserves by its general partner. MEMP GP determines the amount and timing of cash distributions by MEMP and has broad discretion to establish and make additions to MEMP’s reserves in amounts the general partner determines to be necessary or appropriate:

 

   

to provide for the proper conduct of partnership business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

 

   

to comply with applicable law, any of MEMP’s debt instruments or other agreements; and

 

   

to provide funds for distributions to the unitholders and the general partner for any one or more of the next four calendar quarters.

 

Accordingly, cash distributions we receive on our MEMP partner interests may be reduced at any time, or we may not receive any cash distributions from MEMP.

 

The amount of cash that MEMP will be able to distribute to us principally depends upon the amount of cash it can generate from its oil and natural gas production business.

 

A significant decline in MEMP’s earnings or cash distributions would have a negative impact on its distributions to its partners, including us. The amount of cash that MEMP will be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it can generate from its oil and natural gas production business. That amount of cash will fluctuate from quarter to quarter based on, among other things:

 

   

the amount of oil, natural gas and NGLs MEMP produces;

 

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the prices at which MEMP sells its oil, natural gas and NGL production;

 

   

the amount and timing of settlements of its commodity derivatives;

 

   

the level of MEMP’s operating costs, including maintenance capital expenditures and payments to MEMP GP and its affiliates; and

 

   

the level of MEMP’s interest expense, which depends on the amount of its indebtedness and the interest payable thereon.

 

Because of these factors, MEMP may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. In addition, our 50% incentive distribution rights are only entitled to distributions from MEMP in any quarter if MEMP has paid at least $0.54625 on each outstanding common unit and subordinated unit for such quarter. If MEMP reduces its per unit distribution below such amounts, we will receive less cash.

 

Conflicts of interest may arise because the board of directors of MEMP GP has a fiduciary duty to manage the general partner in a manner that is beneficial to the owner of MEMP GP, and at the same time, to manage MEMP in a manner that is beneficial to the MEMP unitholders. Conflicts may also arise because our executive officers have significant equity interests in MEMP.

 

We own MEMP GP, the sole general partner of MEMP. MEMP is a publicly traded limited partnership. The board of directors of MEMP GP owes specified duties to the MEMP unitholders, and also owes specified duties to us as owner of MEMP GP. As a result of these conflicts, the board of directors of MEMP GP may favor the interests of the MEMP public unitholders over our interests.

 

Our executive officers have significant equity interests in MEMP. As of June 30, 2014, Mr. Weinzierl, our Chief Executive Officer, owns 485,093 MEMP common units; Mr. Scarff, our President, owns 90,943 MEMP common units; Mr. Cozby, our Vice President and Chief Financial Officer, owns 152,471 MEMP common units; Mr. Forney, our Vice President and Chief Operating Officer, owns 143,081 MEMP common units; Mr. Roane, our Vice President, General Counsel and Corporate Secretary, owns 83,818 MEMP common units; and Mr. Robbins, our Vice President, Corporate Development, owns 89,782 MEMP common units. As a result of our executive officers’ significant holdings of MEMP common units, our executive officers may favor the interests of MEMP over our interests.

 

If MEMP’s unitholders remove MEMP GP, we would lose our general partner interest and incentive distribution rights in MEMP and the ability to manage MEMP.

 

We currently manage our investment in MEMP through our ownership interest in MEMP GP. MEMP’s partnership agreement, however, gives unitholders of MEMP the right to remove its general partner upon the affirmative vote of holders of 66 2/3% of the MEMP’s outstanding units. If MEMP GP were removed as general partner of MEMP, it would receive cash or common units in exchange for its 0.1% general partner interest and incentive distribution rights and would also lose its ability to manage MEMP. While the cash or common units the general partner would receive are intended under the terms of MEMP’s partnership agreement to fully compensate MEMP GP in the event such an exchange is required, the value of the investments we make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the incentive distribution rights had MEMP GP retained them.

 

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

 

We have a substantial amount of indebtedness. As of June 30, 2014, on a pro forma basis and after giving effect to the consummation of the offering of the MRD Senior Notes in July 2014 and the application of the net

 

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proceeds therefrom, we would have had aggregate indebtedness of approximately $633 million at the MRD Segment. The terms and conditions governing our indebtedness:

 

   

require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

 

   

increase our vulnerability to economic downturns and adverse developments in our business;

 

   

limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

 

   

place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

 

   

place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

 

   

limit management’s discretion in operating our business.

 

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. For example, our existing and future debt agreements will require that we satisfy certain conditions, including coverage and leverage ratios, to borrow money. Our existing and future debt agreements will also restrict the payment of dividends and distributions by certain of our subsidiaries to us, which could affect our access to cash. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

 

We may not be able to generate enough cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations which may not be successful.

 

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Moreover, and subject to certain limitations, we and our subsidiaries may be able to incur substantial additional indebtedness in the future. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and from our subsidiaries and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

 

If we do not generate enough cash flow from operations and from our subsidiaries to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

 

   

refinancing or restructuring our debt;

 

   

selling assets;

 

   

reducing or delaying capital investments; or

 

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seeking to raise additional capital.

 

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition and results of operations.

 

Furthermore, our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our revolving credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our 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 our debt service and other obligations. Our existing debt instruments currently restrict, and we expect our revolving credit facility will restrict, our ability to dispose of assets and our use of the proceeds from such disposition. 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 our scheduled debt service obligations.

 

Risks Relating to this Offering and 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.

 

MRD Holdco, certain former management members of WildHorse Resources and our directors and executive officers have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 60 days following the date of this prospectus. Citigroup Global Markets Inc., at any time, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock 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.

 

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.

 

The trading market for our common stock is 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.

 

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

 

NGP, through the Funds, beneficially owns all of the voting interests in MRD Holdco. Upon completion of this offering, MRD Holdco will own in the aggregate approximately 41% of the combined voting power of our common stock (or approximately 39% if the underwriters option to purchase additional shares of common stock from the selling stockholders is exercised in full). MRD Holdco and certain former management members of

 

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WildHorse Resources (which former management members, upon completion of this offering, will own in the aggregate approximately 19% of the combined voting power of our common stock (or approximately 18% if the underwriters option to purchase additional shares of common stock from the selling stockholders is exercised in full)) are party to a voting agreement, pursuant to which the former management members of WildHorse Resources agree, among other things, to vote all of their shares as directed by MRD Holdco. As a result, MRD Holdco and, thus, NGP are 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.

 

Many of the directors and all of the officers who have responsibility for our management 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.

 

Most of our officers hold similar positions with MRD Holdco and MEMP GP, and many 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, the Funds and their affiliates (including NGP) are in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties, and MRD Holdco and MEMP are both in the business of acquiring and developing oil and natural gas properties. Mr. Hersh, one of our directors, is a managing partner of NGP; Mr. Gieselman, one of our directors, is a managing director of NGP; Mr. Weber, one of our directors, is a managing partner of NGP and serves as Chief Operating Officer for NGP; Mr. Innamorati, one of our directors, is a director of MEMP GP, and Mr. Weinzierl, our Chief Executive Officer and one of our directors, is the Chief Executive Officer and Chairman of MEMP GP, and was a managing director and operating partner of NGP and continues to hold ownership interests in the Funds and certain of their affiliates. Our officers will continue to devote significant time to the business of MEMP and MRD Holdco and face conflicts in allocating their time on our behalf and on behalf of MEMP GP and MRD Holdco. Our officers have also historically received a significant portion of their overall compensation in MEMP unit awards under the long term incentive plan of MEMP GP. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and MRD Holdco, MEMP, or the Funds, on the other hand, will be resolved in our favor. The existing positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These officers and 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.”

 

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The corporate opportunity provisions in our amended and restated certificate of incorporation could enable NGP, MRD Holdco or the Funds to benefit from corporate opportunities that might otherwise be available to us.

 

Subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things:

 

   

permits any of NGP, MRD Holdco, the Funds, their respective affiliates, or our officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

   

provides that if NGP, MRD Holdco, the Funds or their respective affiliates or any director or officer of one of our affiliates, NGP, MRD Holdco, the Funds or their respective affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

 

As a result, NGP, MRD Holdco, the Funds or their 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 to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to NGP, MRD Holdco or the Funds and their 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.”

 

We are a “controlled company” within the meaning of the NASDAQ rules and, as a result, qualify for, and rely on, exemptions from certain corporate governance requirements.

 

MRD Holdco and certain former management members of WildHorse Resources, as a group, control a majority of our voting common stock. As a result, we are a “controlled company” within the meaning of applicable corporate governance standards. Under the NASDAQ rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements, including:

 

   

the requirement that we have a majority of independent directors on our Board;

 

   

the requirement that we have a nominating committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

 

   

the requirement that we have a compensation committee that is composed entirely of independent directors; and

 

   

the requirement for an annual performance evaluation of the nominating and compensation committees.

 

We utilize the foregoing exemptions from the applicable corporate governance requirements. As a result, we do not have a majority of independent directors and do not have a compensation committee. See “Management.” Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to all of the applicable corporate governance requirements.

 

The price of our common stock may fluctuate significantly and you could lose all or part of your investment.

 

Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could fluctuate significantly for various reasons, including:

 

   

our operating and financial performance and prospects;

 

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changes in earnings estimates or recommendations by securities analysts who track our common stock or industry;

 

   

market and industry perception of our success, or lack thereof, in pursuing our growth strategy; and

 

   

sales of common stock by us, our stockholders (including the Funds), or members of our management team.

 

In addition, the stock market has experienced significant price and volume fluctuations in recent years. This volatility has had a significant impact on the market price of securities issued by many companies, including companies in our industries. The changes frequently appear to occur without regard to the operating performance of the affected companies. Hence, the price of our common stock could fluctuate based upon factors that have little or nothing to do with us, and these fluctuations could materially reduce our share price.

 

We currently have no plans to pay regular dividends on our common stock, so you may not receive funds without selling your common stock.

 

We currently have no plans to pay regular dividends on our common stock. Any payment of dividends in the future will be at the discretion of our Board and will depend on, among other things, our earnings, financial condition and business opportunities, the restrictions in our debt agreements, and other considerations that our Board deems relevant. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.

 

Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.

 

We may sell additional shares of common stock in subsequent public offerings or otherwise, including to finance acquisitions. Our amended and restated certificate of incorporation authorizes us to issue 600,000,000 shares of common stock, of which 193,559,211 shares are outstanding. The outstanding share number includes 49,220,000 shares registered and sold in our initial public offering and up to 31,968,125 shares that the selling stockholders are selling in this offering (assuming the underwriters exercise their option to acquire additional shares in full), all of which may be resold immediately in the public market. Following the expiration of the applicable lock-up period, which is 60 days after the date of this prospectus, 115,481,632 shares of our common stock may be sold into the public market (assuming the underwriters do not exercise their option to acquire additional shares), subject to compliance with the Securities Act or exemptions therefrom. See “Shares Eligible for Future Sale” for a discussion of the shares of our common stock that may be sold into the public market in the future.

 

MRD Holdco and certain former management members of WildHorse Resources are party to the Registration Rights Agreement, which requires us to effect the registration of their shares in certain circumstances. Upon the effectiveness of such a registration statement, all shares covered by the registration statement would be freely transferable without restriction or further registration under the Securities Act, except for any such shares which are acquired by any of our “affiliates” as that term is defined in Rule 144 under the Securities Act, which will be subject to the resale limitations of Rule 144. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

 

We filed a registration statement with the SEC on Form S-8 providing for the registration of 19,250,000 shares of our common stock issued or reserved for issuance under our Memorial Resource Development Corp. 2014 Long Term Incentive Plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under our registration statement on Form S-8 are available for resale immediately in the public market without restriction.

 

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial

 

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amounts of our common stock (including any shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

 

Our organizational documents and the voting agreement may impede or discourage a takeover, which could deprive our investors of the opportunity to receive a premium for their shares.

 

Provisions of our amended and restated certificate of incorporation, our amended and restated bylaws and the voting agreement may make it more difficult for, or prevent a third party from, acquiring control of us. These provisions include:

 

   

requiring that certain former management members of WildHorse Resources vote all of their shares of our common stock, including with respect to the election of our directors, as directed by MRD Holdco;

 

   

at such time MRD Holdco, NGP or as the Funds no longer beneficially own or control the voting of more than 50% of our outstanding common stock, our Board will be divided into three classes with each class serving staggered three year terms;

 

   

at such time MRD Holdco, NGP or as the Funds no longer beneficially own or control the voting of more than 50% of our outstanding common stock, any action by stockholders may only be taken at an annual meeting or special meeting and may no longer be effected by a written consent of the stockholders, subject to the rights of any series of preferred stock with respect to such rights;

 

   

at such time as MRD Holdco, NGP or the Funds no longer beneficially own or control the voting of more than 50% of our outstanding common stock, special meetings of our stockholders may only be called by our Board 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);

 

   

at such time as MRD Holdco, NGP or the Funds no longer beneficially own or control the voting of more than 50% of our outstanding common stock, 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, shall be required to remove any or all of the directors from office at any time;

 

   

prohibiting cumulative voting in the election of directors; and

 

   

authorizing the issuance of “blank check” preferred stock without any need for action by stockholders.

 

Our issuance of shares of preferred stock could delay or prevent a change in control of us. Our Board has authority to issue shares of preferred stock without stockholder approval 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. The issuance of shares of our preferred stock may have the effect of delaying, deferring or preventing a change in control without further action by the stockholders, even where stockholders are offered a premium for their shares.

 

Together, our amended and restated certificate of incorporation, amended and restated bylaws and the voting agreement could make the removal of management more difficult and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our common stock. Furthermore, the existence of the foregoing provisions, as well as the significant amount of common stock beneficially owned by the Funds, could limit the price that investors might be willing to pay in the future for shares of our common stock. They could also deter potential acquirers of us, thereby reducing the likelihood that you could receive a premium for your common stock in an acquisition. See “Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware Law.”

 

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We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

 

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies, as described under the caption “Certain Relationships and Related Party Transactions.” The resolution of any conflicts that may arise in connection with any related party transactions that we have entered into with MEMP, NGP, MRD Holdco, the Funds or their affiliates, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because NGP or the Funds may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, please read “—NGP has the ability to direct the voting of more than a majority of our common stock, and its interests may conflict with those of our other stockholders.”

 

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 authorizes 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 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. See “Description of Capital Stock—Limitation of Liability and Indemnification Matters.”

 

The additional requirements of having a class of publicly traded equity securities may strain our resources and distract management.

 

As a public company, we are subject to additional reporting requirements of the Securities and Exchange Act of 1934 (the “Exchange Act”), the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act. The Dodd-Frank Act effects comprehensive changes to public company governance and disclosures in the United States and subject to additional federal regulation. We cannot predict with any certainty the requirements of the regulations ultimately adopted or how the Dodd-Frank Act and such regulations will impact the cost of compliance for a company with publicly traded common stock. We are currently evaluating and monitoring developments with respect to the Dodd-Frank Act and other new and proposed rules and cannot predict or estimate the amount of the additional costs we may incur or the timing of such costs. These laws, regulations and standards are subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing bodies due to ambiguities related to practice, regulatory authorities may initiate legal proceedings against us and our business may be harmed. We also expect that being a company with publicly traded common stock and these new rules and regulations will make it more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our Board, particularly to serve on our audit committee, and qualified executive officers.

 

The Sarbanes-Oxley Act requires that we maintain effective disclosure controls and procedures and internal control over financial reporting. These requirements may place a strain on our systems and resources. Under

 

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Section 404 of the Sarbanes-Oxley Act, we will be required to include a report of management on our internal control over financial reporting in our Annual Reports on Form 10-K beginning with the Form 10-K for the year ending December 31, 2014. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight are required. This may divert management’s attention from other business concerns, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. If we are unable to conclude that our disclosure controls and procedures and internal control over financial reporting are effective, or if we are no longer an emerging growth company and our independent public accounting firm is unable to provide us with an unqualified report on our internal control over financial reporting in future years, investors may lose confidence in our financial reports and our stock price may decline.

 

We may remain an “emerging growth company” for up to five years. After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act.

 

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors.

 

We are an “emerging growth company,” as defined in the JOBS Act, and we currently take advantage of certain exemptions from various reporting requirements that are applicable to other public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an “emerging growth company.” We cannot predict if investors will find our common stock less attractive because we rely and will continue to rely on these exemptions. If some investors find our common stock 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.

 

We will cease to be an “emerging growth company” upon the earliest of (i) the last day of the fiscal year in which we have $1.0 billion or more in annual revenues, (ii) 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), (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period, or (iv) 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 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.

 

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.

 

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If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, our shareholders 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 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 of 2002. Any failure to 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.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This prospectus contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, are forward-looking statements. When used in this prospectus, the words “could,” “should,” “will,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “plan,” “potential,” “pursue,” “target,” “project,” “forecast,” the negative of such terms, or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

 

Forward-looking statements may include statements about:

 

   

our business strategy;

 

   

our estimated reserves and the present value thereof;

 

   

our technology;

 

   

our cash flows and liquidity;

 

   

our financial strategy, budget, projections and future operating results;

 

   

realized commodity prices;

 

   

timing and amount of future production of reserves;

 

   

availability of drilling and production equipment;

 

   

availability of pipeline capacity;

 

   

availability of oilfield labor;

 

   

the amount, nature and timing of capital expenditures, including future development costs;

 

   

availability and terms of capital;

 

   

drilling of wells, including statements made about future horizontal drilling activities;

 

   

competition;

 

   

government regulations;

 

   

marketing of production;

 

   

exploitation or property acquisitions;

 

   

costs of exploiting and developing our properties and conducting other operations;

 

   

general economic and business conditions;

 

   

competition in the oil and natural gas industry;

 

   

effectiveness of our risk management activities;

 

   

environmental and other liabilities;

 

   

counterparty credit risk;

 

   

taxation of the oil and natural gas industry;

 

   

developments in other countries that produce oil and natural gas;

 

   

uncertainty regarding future operating results;

 

   

plans and objectives of management; and

 

   

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

 

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These types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in “Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this prospectus. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

 

   

variations in the market demand for, and prices of, oil, natural gas and NGLs;

 

   

uncertainties about our estimated reserves;

 

   

the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;

 

   

general economic and business conditions;

 

   

risks associated with negative developments in the capital markets;

 

   

failure to realize expected value creation from property acquisitions;

 

   

uncertainties about our ability to replace reserves and economically develop our current reserves;

 

   

drilling results;

 

   

potential financial losses or earnings reductions from our commodity price risk management programs;

 

   

adoption or potential adoption of new governmental regulations;

 

   

the availability of capital on economic terms to fund our capital expenditures and acquisitions;

 

   

risks associated with our substantial indebtedness; and

 

   

our ability to satisfy future cash obligations and environmental costs.

 

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors” section of this prospectus and elsewhere in this prospectus. All forward-looking statements speak only as of the date on which they are made. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

 

We will not receive any proceeds from the sale of shares of our common stock by the selling stockholders, including pursuant to any exercise by the underwriters of their option to purchase additional shares of our common stock. The selling stockholders may be deemed under federal securities laws to be underwriters with respect to the common stock they may sell in connection with this offering.

 

DIVIDEND POLICY

 

We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant.

 

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MARKET PRICE OF OUR COMMON STOCK

 

Our common stock began trading on the NASDAQ under the symbol “MRD” on June 13, 2014. Prior to that, there was no public market for our common stock. On September 30, 2014, the last reported sale price for our common stock on the NASDAQ was $27.11 per share. As of September 30, 2014, we had approximately 193,559,211 shares of common stock issued and outstanding and 64 stockholders of record. The following table sets forth, for the periods indicated, the reported high and low sale prices for our common stock on the NASDAQ.

 

     High      Low  

Third Quarter 2014

   $ 30.32       $ 22.50   

Second Quarter 2014 (beginning June 13, 2014)

   $ 25.90       $ 21.07   

 

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SELECTED HISTORICAL FINANCIAL DATA

 

Prior to the closing of our initial public offering, MRD LLC and its consolidated subsidiaries, our accounting predecessor, controlled MEMP through its ownership of MEMP GP, the general partner of MEMP. Because MRD LLC controlled MEMP through its ownership of the general partner, MRD LLC was required to consolidate MEMP for accounting and financial reporting purposes even though MRD LLC owned a minority of its partner interests and MRD LLC and MEMP had independent capital structures. MRD LLC received cash distributions from MEMP as a result of its partner interests and incentive distribution rights in MEMP, when declared and paid by MEMP. In connection with the closing of our initial public offering, MRD LLC contributed substantially all of its existing assets to us in exchange for shares of our common stock. Through our ownership of MEMP GP, we continue to control MEMP and therefore continue to consolidate the results of MEMP into our consolidated financial statements in current and future periods.

 

Our predecessor had two reportable business segments, both of which were engaged in the acquisition, exploitation, development and production of oil and natural gas properties:

 

   

MRD—reflected all of MRD LLC’s consolidating subsidiaries except for MEMP and its subsidiaries.

 

   

MEMP—reflected the consolidated and combined operations of MEMP and its subsidiaries.

 

We continue to have two reportable segments. For more information regarding reportable business segments, please see the predecessor’s audited historical financial statements and related notes and our unaudited historical interim financial statements included elsewhere in this prospectus.

 

The following tables include selected historical financial data for us and our predecessor, as well as the MRD Segment as of and for the periods indicated. The selected historical financial data of our predecessor as of and for the years ended December 31, 2013 and 2012 were derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus. The selected historical financial data as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 were derived from our unaudited interim financial statements included elsewhere in this prospectus. The selected historical financial data of the MRD Segment as of and for the years ended December 31, 2013 and 2012 were derived from certain financial information used in the preparation of our predecessor’s audited financial statements. The selected historical financial data for the MRD Segment as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 were derived from certain financial information used in the preparation of our unaudited interim financial statements.

 

The selected unaudited pro forma data as of June 30, 2014 has been prepared to give pro forma effect to MEMP’s July 2014 acquisition of certain oil and natural gas liquids properties in Wyoming (the “MEMP Wyoming Acquisition”), MEMP’s July and September 2014 equity offerings (the “MEMP Offerings”) and our private placement on July 10, 2014 of $600.0 million aggregate principal amount of 5.875% senior unsecured notes at par as well as MEMP’s private placement on July 17, 2014 of $500.0 million aggregate principal amount of 6.875% senior unsecured notes at 98.485% of par (collectively referred to as the “Debt Offerings”).

 

The selected unaudited pro forma data for the six months ended June 30, 2014 and for the year ended December 31, 2013 has been prepared to give pro forma effect to: (i) the exclusion of both BlueStone and Classic Pipeline as well as the MEMP subordinated units, none of which were conveyed to us in connection with our initial public offering; (ii) certain restructuring transactions that took place in connection with our initial public offering; (iii) the MEMP Wyoming Acquisition and the MEMP Offerings; (iv) the Debt Offerings; and (v) incremental federal income tax expense.

 

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We derived the data in the following tables from, and the following tables should be read together with and is qualified in its entirety by reference to, our historical financial statements (including those of our predecessor) and our pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our pro forma and historical consolidated financial statements, all included elsewhere in this prospectus. Among other things, those historical consolidated and combined financial statements and pro forma financial statements include more detailed information regarding the basis of presentation for the following data.

 

           Memorial Resource Development
Corp. Pro Forma
 
     Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended June 30,
 
     2013     2012     2014     2013     2013     2014  
     (Predecessor)           (Predecessor)        
                 (unaudited)     (unaudited)  
     (in thousands)  

Statement of Operations Data:

            

Revenues:

            

Oil and natural gas sales

   $ 571,948      $ 393,631      $ 425,140      $ 268,095      $ 740,221      $ 514,650   

Other revenues

     3,075        3,237        2,252        1,131        2,268        1,702   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     575,023        396,868        427,392        269,226        742,489        516,352   

Costs and expenses:

            

Lease operating

     113,640        103,754        65,676        52,351        165,092        90,350   

Pipeline operating

     1,835        2,114        1,165        949        1,835        1,165   

Exploration

     2,356        9,800        1,290        973        2,356        1,290   

Production and ad valorem taxes

     27,146        23,624        19,583        16,056        53,079        31,475   

Depreciation, depletion and amortization

     184,717        138,672        131,459        87,192        233,244        159,910   

Impairment of proved oil and gas properties

     6,600        28,871        —          —          4,201        —     

Incentive unit compensation expense

     —          —          943,840        —          —          943,840   

General and administrative

     125,358        69,187        39,865        36,336        101,098        38,826   

Accretion of asset retirement obligations

     5,581        5,009        3,048        2,662        5,803        3,188   

(Gain) loss on commodity derivatives

     (29,294     (34,905     201,072        (31,584     (29,311     201,072   

(Gain) loss on sale of property

     (85,621     (9,761     3,057        3,845        3,927        3,167   

Other, net

     649        502        (12     598        649        (12
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     352,967        336,867        1,410,043        169,378        541,973        1,474,271   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     222,056        60,001        (982,651     99,848        200,516        (957,919
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

            

Interest expense, net

     (69,250     (33,238     (68,583     (21,379     (117,843     (70,015

Loss on extinguishment of debt

     —          —          (37,248     —          —          (37,248

Amortization of investment premium

     —          (194     —          —          —          —     

Other, net

     145        535        87        57        143        87   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (69,105     (32,897     (105,744     (21,322     (117,700     (107,176

Income tax benefit (expense)

     (1,619     (107     11,436        (188     (29,814     3,048   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 151,332      $ 26,997      $ (1,076,959   $ 78,338      $ 53,002      $ (1,062,047
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data:

            

Net cash provided by operating activities

   $ 277,823      $ 240,404      $ 177,747      $ 163,142       

Net cash used in investing activities

     367,443        606,738        483,736        201,129       

Net cash provided by financing activities

     117,950        361,761        244,234        59,687       

Balance Sheet Data (at period end):

            

Working capital (deficit)

   $ 48,256      $ 63,054      $ (60,022       $ (65,614

Total assets

     2,829,161        2,459,304        3,043,920            3,921,945   

Total debt

     1,663,217        939,382        1,767,806            2,096,112   

Total equity (including noncontrolling interests)

     858,132        1,276,709        816,652            1,357,280   

 

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<
     MRD Segment     MRD Segment
Pro Forma
 
     Year Ended
December 31,
    Six Months Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended June 30,
 
     2013     2012     2014     2013     2013     2014  
                 (unaudited)     (unaudited)  
     (in thousands)  

Statement of Operations Data:

            

Revenues:

            

Oil and natural gas sales

   $ 230,751      $ 138,032      $ 202,594      $ 110,834      $ 212,603      $ 200,905   

Other revenues

     807        782        556        233               6   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     231,558        138,814        203,150        110,067        212,603        200,911   

Costs and expenses:

            

Lease operating

     25,006        24,438        11,666        10,921        23,354        11,732   

Exploration

     1,226        7,337        1,080        698        1,226        1,080   

Production and ad valorem taxes

     9,362        7,576        6,923        7,209        8,485        6,872   

Depreciation, depletion and amortization

     87,043        62,636        67,946        42,129        76,524        67,203   

Impairment of proved oil and gas properties

     2,527        18,339        —          —          128        —     

Incentive unit compensation expense

     —          —          943,840        —          —          943,840   

General and administrative

     81,758        38,414        19,319        14,813        57,498        18,280   

Accretion of asset retirement obligations

     728        632        325        369        670        325   

(Gain) loss on commodity derivatives

     (3,013     (13,488     15,960        (8,574     (3,030     15,960   

(Gain) loss on sale of property

     (82,773     (2     3,057