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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on July 22, 2013

Registration No. 333-189109

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



Amendment No. 3
to

FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933



Athlon Energy Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  46-2549833
(I.R.S. Employer
Identification Number)

420 Throckmorton Street, Suite 1200
Fort Worth, Texas 76102
(817) 984-8200

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

Robert C. Reeves
President and Chief Executive Officer
420 Throckmorton Street, Suite 1200
Fort Worth, Texas 76102
(817) 984-8200
(Name, address, including zip code, and telephone number, including area code, of agent for service)



Copies to:
Sean T. Wheeler
Divakar Gupta
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400
  Gerald M. Spedale
Jason A. Rocha
Baker Botts L.L.P.
910 Louisiana Street
Houston, Texas 77002
(713) 229-1234

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

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

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

          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. o

          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. o

          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 o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o

CALCULATION OF REGISTRATION FEE

               
 
Title of Each Class of Securities to Be Registered
  Amount to be Registered(1)
  Proposed Maximum Offering Price per Share(2)
  Proposed Maximum Aggregate Offering Price(1)(2)
  Amount of
Registration
Fee

 

Common Common Stock, par value $0.01 per share

  18,157,895   $20.00   $363,157,900   $49,535(3)

 

(1)
Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes 2,368,421 additional shares of common stock that the underwriters have the option to purchase.
(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(a) under the Securities Act of 1933, as amended.
(3)
The Registrant previously paid $47,058 of the total registration fee in connection with prior filings of this Registration Statement. Concurrently with the filing of this Amendment No. 3 to the Registration Statement, the Registrant has transmitted $2,477, representing the additional filing fee payable with respect to the $18,157,900 increase in the proposed maximum aggregate offering price set forth herein.

          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 or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

   


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

Subject to Completion, dated July 22, 2013

PROSPECTUS

LOGO

15,789,474 Shares

Athlon Energy Inc.

Common Stock
$      per share



        This is the initial public offering of our common stock. We are selling 15,789,474 shares of our common stock. We expect the initial public offering price to be between $18.00 and $20.00 per share.

        The selling stockholders named in this prospectus have granted the underwriters an option to purchase up to 2,368,421 additional shares of common stock to cover over-allotments. We will not receive any of the proceeds from the sale of the shares by the selling stockholders.

        We have been approved to list our common stock on the New York Stock Exchange under the symbol "ATHL."



        Investing in our common stock involves risks. See "Risk Factors" beginning on page 18.

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

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



 
  Per Share   Total
Initial Public Offering Price   $   $
Underwriting Discounts and Commissions(1)   $   $
Proceeds to Athlon Energy Inc. (before expenses)   $   $

(1)
Please read "Underwriting (Conflicts of Interest)" for a description of all underwriting compensation payable in connection with this offering.

        The underwriters expect to deliver the shares to purchasers on or about                        , 2013 through the book-entry facilities of The Depository Trust Company.



Citigroup       Goldman, Sachs & Co.
BofA Merrill Lynch   UBS Investment Bank   Wells Fargo Securities



Barclays   Credit Suisse   RBC Capital Markets

Scotiabank / Howard Weil   Tudor, Pickering, Holt & Co.

Apollo Global Securities   CIBC   Credit Agricole CIB   FBR

Lebenthal Capital Markets   Mitsubishi UFJ Securities   Simmons & Company
 International
  Stephens Inc.



                        , 2013


Table of Contents

GRAPHIC



TABLE OF CONTENTS

Prospectus Summary

  1

The Offering

  10

Summary Consolidated Financial, Reserve and Operating Data

  12

Risk Factors

  18

Cautionary Note Regarding Forward-Looking Statements

  49

Use of Proceeds

  51

Dividend Policy

  51

Capitalization

  52

Dilution

  53

Selected Historical Consolidated Financial Data

  54

Management's Discussion and Analysis of Financial Condition and Results of Operations

  55

Business

  82

Management

  106

Certain Relationships and Related Party Transactions

  124

Corporate Reorganization

  130

Principal and Selling Stockholders

  132

Description of Capital Stock

  134

Shares Eligible for Future Sale

  141

Material U.S. Federal Income Tax Consequences to Non-U.S. Holders

  143

Underwriting (Conflicts of Interest)

  147

Legal Matters

  155

Experts

  155

Where You Can Find More Information

  155

Glossary

  G-1

Index to Financial Statements

  F-1

        You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock.

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 also based on our good faith estimates. Although we believe these third-party sources are reliable, neither we nor the underwriters have independently verified the information and cannot guarantee its accuracy and completeness. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled "Risk Factors." These and other factors could cause results to differ materially from those expressed in these publications.

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PROSPECTUS SUMMARY

        This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and the related notes thereto appearing elsewhere in this prospectus. We have provided definitions for certain terms used in this prospectus in the "Glossary" appearing elsewhere in this prospectus. References to our estimated proved reserves and PV-10 are derived from our proved reserve reports prepared by Cawley, Gillespie & Associates, Inc.

        In this prospectus, unless the context otherwise requires, the terms "we," "us," "our" and "Athlon" refer to Athlon Holdings LP and its subsidiaries before the completion of our corporate reorganization in April 2013 and Athlon Energy Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter. Please read "Corporate Reorganization." Unless otherwise indicated, the information contained in this prospectus assumes that the underwriters do not exercise their option to purchase additional shares from Apollo and that the New Holdings Units subject to the terms of the exchange agreement are not exchanged for shares of our common stock. The information throughout this prospectus assumes and gives effect to a 65.459 for 1 stock split that will be effected as of the effective date of the registration statement of which this prospectus forms a part.

Overview

        We are an independent exploration and production company focused on the acquisition, development and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin. The Permian Basin spans portions of Texas and New Mexico and is composed of three primary sub-basins: the Delaware Basin, the Central Basin Platform and the Midland Basin. All of our properties are located in the Midland Basin. Our drilling activity is currently focused on the low-risk vertical development of stacked pay zones, including the Spraberry, Wolfcamp, Cline, Strawn, Atoka and Mississippian formations, which we refer to collectively as the Wolfberry play. We are a returns-focused organization and have targeted the Wolfberry play in the Midland Basin because of its favorable operating environment, consistent reservoir quality across multiple target horizons, long-lived reserve characteristics and high drilling success rates.

        We were founded in August 2010 by a group of former executives from Encore Acquisition Company following its acquisition by Denbury Resources, Inc. With an average of approximately 20 years of industry experience and over 10 years of history working together, our founding management has a proven track record of working as a team to acquire, develop and exploit oil and natural gas reserves in the Permian Basin as well as other resource plays in North America.

        Our acreage position was 124,925 gross (98,348 net) acres at May 31, 2013, which we group into three primary areas based on geographic location within the Midland Basin: Howard, Midland & Other and Glasscock. From the time we began operations in January 2011 through May 31, 2013, we have operated up to eight vertical drilling rigs simultaneously and have drilled 230 gross operated vertical Wolfberry wells with a 99% success rate across all three areas. This activity has allowed us to identify and de-risk our multi-year inventory of 4,902 gross (3,857 net) vertical drilling locations, while also identifying 1,079 gross (931 net) horizontal drilling locations in specific areas based on geophysical and technical data. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify additional horizontal drilling locations.

 

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        The following table summarizes our leasehold position and identified net drilling locations by primary geographic area as of May 31, 2013:

 
   
   
  Identified Drilling Locations1  
 
   
   
  Vertical    
 
 
  Acreage    
 
 
  Net
40-acre2
  Net
20-acre
  Net
Total
  Drilling
Inventory3
(years)
  Net
Horizontal4
 
 
  Gross   Net  

Howard

    69,661     51,556     1,140     1,291     2,431     37     403  

Midland & Other

    36,694     33,709     390     414     804     20     316  

Glasscock

    18,570     13,083     267     355     622     24     212  
                                 

Total

    124,925     98,348     1,797     2,060     3,857     30     931  
                               

1
Represents locations specifically identified by management based on evaluation of applicable geologic, engineering and production data. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

2
Includes 597 gross (560 net) locations booked as proved undeveloped locations in our proved reserve report as of December 31, 2012.

3
Based on our 2013 drilling program on a gross basis.

4
Includes horizontal drilling locations targeting Wolfcamp A, Wolfcamp B, Wolfcamp C, Cline and Mississippian intervals, which comprise 311 gross (272 net), 357 gross (317 net), 133 gross (125 net), 227 gross (193 net) and 51 gross (24 net) locations, respectively.

        Since our inception, we have completed two significant acquisitions and seven bolt-on acquisitions. At the time of each acquisition, based on internal engineering estimates, these properties collectively contributed approximately 3,600 BOE/D of production and approximately 43 MMBOE of proved reserves. We have significantly grown production and proved reserves on the properties we acquired through the successful execution of our low-risk vertical drilling program. From the time we began operations in January 2011 through May 31, 2013, we have drilled 230 gross operated vertical Wolfberry wells on our properties with a 99% success rate and grown our production to 11,957 BOE/D for June 2013.

        In 2012, our development capital was approximately $276 million and we drilled a total of 133 gross (124 net) vertical Wolfberry wells. In 2013, we plan to invest $317 million of development capital, including $15 million for infrastructure, leasing and capitalized workovers, and drill 162 gross (150 net) vertical Wolfberry wells. We also plan to invest $33 million of development capital to drill 4 gross (4 net) horizontal Wolfcamp wells. We currently operate seven vertical drilling rigs on our properties and have operated between five and eight vertical drilling rigs since October 2011. We expect to take delivery of our first horizontal rig in the third quarter of 2013 and our second horizontal rig in the second quarter of 2014.

        Our estimate of proved reserves is prepared by Cawley, Gillespie & Associates, Inc. ("CG&A"), our independent petroleum engineers. As of December 31, 2012, we had 86 MMBOE of proved reserves, which were 58% oil, 22% NGLs and 20% natural gas and 30% proved developed. As of December 31, 2012, the PV-10 of our proved reserves was approximately $867 million, 59% of which was attributed to proved developed reserves. Our proved undeveloped reserves, or PUDs, are composed of 597 gross (560 net) potential vertical drilling locations. The following table provides

 

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information regarding our proved reserves and production by area as of December 31, 2012, except as otherwise noted below:

 
  Estimated Total Proved Reserves    
   
 
 
  Average Net
Daily
Production3
(BOE/D)
   
 
 
  Oil
(MMBbls)
  NGLs
(MMBbls)
  Natural
Gas
(Bcf)
  Total
(MMBOE)
  % Liquids1   PV-102
(in millions)
  R/P
Ratio
(years)
 

Howard

    20.2     7.3     36.3     33.5     82 % $ 365.4     4,392     20.9  

Midland & Other

    17.6     8.3     44.7     33.3     78 %   337.0     5,702     16.0  

Glasscock

    11.6     3.7     22.7     19.2     80 %   164.2     1,863     28.2  
                                       

Total

    49.4     19.3     103.7     86.0     80 % $ 866.6     11,957     19.7  
                                   

1
Includes both oil and NGLs.

2
PV-10 is a non-GAAP financial measure. Standardized Measure is the closest GAAP measure and our Standardized Measure was $850.9 million at December 31, 2012. For additional information about PV-10 and how it differs from the Standardized Measure, please read "Summary Consolidated Financial, Reserve and Operating Data—Non-GAAP Financial Measures."

3
During June 2013, inclusive of oil production of 6,895 Bbls/D in total.

Our Business Strategy

        We maintain a disciplined and analytical approach to investing in which we seek to direct capital in a manner that will maximize our rates of return as we develop our extensive resource base. Key elements of our strategy are:

    Grow reserves, production and cash flow with our multi-year inventory of low-risk vertical drilling locations.  We have considerable experience managing large scale drilling programs and intend to efficiently develop our acreage position to maximize the value of our resource base. During 2012, we invested $276 million of development capital, drilled 133 gross (124 net) vertical Wolfberry wells and grew production by 4,204 BOE/D, or 93%, from 4,506 BOE/D in the fourth quarter of 2011 to 8,710 BOE/D in the fourth quarter of 2012. We also increased proved reserves by 40 MMBOE, or 86%, from 46 MMBOE at December 31, 2011 to 86 MMBOE at December 31, 2012. In 2013, we plan to invest approximately $317 million of development capital, including $15 million for infrastructure, leasing and capitalized workovers, and drill 162 gross (150 net) vertical Wolfberry wells. We also plan to invest $33 million of development capital to drill 4 gross (4 net) horizontal Wolfcamp wells in order to continue to grow our production and reserves.

    Continuously improve capital and operating efficiency.  We continuously focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating cost per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. Additionally, we seek to build infrastructure that allows us to achieve economies of scale and reduce operating costs. Specifically, we have:

    achieved first six-month average daily production volumes on our operated wells in Howard County that outperformed average industry vertical well results by 102% since 2010, based on data from the Texas Railroad Commission;

    achieved first six-month average daily production volumes on our operated wells in Midland County that outperformed average industry vertical well results by 68% since 2010, based on data from the Texas Railroad Commission;

 

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      reduced average development costs per gross well in our Midland & Other area from $2.4 million in the first quarter of 2012 to $2.1 million in the first quarter of 2013, an improvement of 9%;

      reduced average development costs per gross well in our Howard and Glasscock areas from $2.0 million in the first quarter of 2012 to $1.8 million in the first quarter of 2013, an improvement of 12%;

      reduced the time from spud to rig release in our Howard and Glasscock areas from 16 days in the fourth quarter of 2011 to 8 days in the first quarter of 2013, an improvement of 50%; and

      reduced LOE from $13.82 per BOE for 2011 to $9.89 per BOE for 2012, an improvement of 28%.

    Balance capital allocation between our lower risk vertical drilling program and horizontal development opportunities.  We have historically focused on optimizing our vertical drilling and completion techniques across our acreage position. Vertical drilling involves less operational, financial and other risk than horizontal drilling, and we view our vertical development drilling program as "low risk" because the drilling locations were selected based on our extensive delineation drilling and production history in the area and well-established industry activity surrounding our acreage. Many operators in the Midland Basin are actively drilling horizontal wells, which is more expensive than drilling vertical Wolfberry wells but potentially recovers disproportionately more hydrocarbons per well. We monitor industry horizontal drilling activity and intend to utilize the knowledge gained from the increase in industry horizontal drilling in the Midland Basin. In the second half of 2013, we intend to supplement our vertical drilling with horizontal drilling in circumstances where we believe that horizontal drilling should offer competitive rates of return.

    Evaluate and pursue oil-weighted acquisitions where we can add value through our technical expertise and knowledge of the basin.  We have significant experience acquiring and developing oil-weighted properties in the Permian Basin, and we expect to continue to selectively acquire additional properties in the Permian Basin that meet our rate-of-return objectives. Since our formation, we have completed two significant acquisitions and seven bolt-on acquisitions that have given us a unique and highly attractive acreage position, underpinned by strong baseline production and proved reserves. We believe our experience as a leading operator and our infrastructure footprint in the Permian Basin provide us with a competitive advantage in successfully executing and integrating acquisitions.

    Maintain a disciplined, growth-oriented financial strategy.  We intend to fund our growth predominantly with internally generated cash flows while maintaining ample liquidity and access to capital markets. Substantially all of our lease terms allow us to allocate capital among projects in a manner that optimizes both costs and returns, resulting in a highly efficient drilling program. In addition, these terms allow us to adjust our capital spending depending on commodity prices and market conditions. We expect our cash flows from operating activities, availability under our credit agreement and the net proceeds of this offering to be sufficient to fund our capital expenditures and other obligations necessary to execute our business plan in 2013. Furthermore, we plan to hedge a significant portion of our expected production in order to stabilize our cash flows and maintain liquidity, allowing us to sustain a consistent drilling program, thereby preserving operational efficiencies that help us achieve our targeted rates of return.

 

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Our Competitive Strengths

        We have a number of competitive strengths that we believe will help us to successfully execute our business strategies, including:

    High caliber management team with substantial technical and operational expertise.  Our founding management team has an average of approximately 20 years of industry experience and over 10 years of history working together with a proven track record of value creation at publicly traded oil and natural gas companies, including Encore Acquisition Company, XTO Energy Inc., Apache Corporation and Anadarko Petroleum Corporation. As of May 31, 2013, we had 23 engineering, land and geosciences technical personnel in our Fort Worth and Midland offices, with personnel experienced in both conventional and unconventional drilling operations. We believe our management and technical team is one of our principal competitive strengths due to our team's industry experience and history of working together in the identification, execution and integration of acquisitions, cost efficient management of profitable, large scale drilling programs and disciplined allocation of capital focused on rates of return.

    High quality asset base with significant oil exposure in the Midland Basin.  Our acreage is concentrated in Howard, Midland and Glasscock counties, which are some of the most active counties in the Midland Basin. Since 2010, more vertical wells have been drilled in each of Howard and Glasscock counties than any other county in the Midland Basin, and Midland County has been the fifth most active county, based on data from the Texas Railroad Commission. Of the 9,242 vertical wells drilled in the Midland Basin since 2010, 1,579 (17%) have been drilled in Howard County, 1,255 (14%) have been drilled in Glasscock County and 714 (8%) have been drilled in Midland county. Furthermore, we have intentionally focused on crude oil and liquids opportunities to benefit from the relative disparity between oil and natural gas prices on an energy-equivalent basis, which has persisted over the last several years and which we expect to continue in the future. Approximately 58% and 22% of our proved reserves were oil and NGLs, respectively, as of December 31, 2012.

    De-risked Midland Basin acreage position with multi-year vertical drilling inventory.  Since our management team commenced our development program in January 2011 through May 31, 2013, we have drilled 230 gross operated vertical Wolfberry wells across our leasehold position with a 99% success rate. Based on our extensive analysis of geophysical and technical data gained as a result of our vertical drilling program and from offset operator activity, as of May 31, 2013, we have identified 2,298 gross (1,797 net) vertical drilling locations on 40-acre spacing and an additional 2,604 gross (2,060 net) vertical drilling locations on 20-acre spacing across our leasehold, all of which target crude oil and NGLs as the primary objectives across stacked pay zones. Together, these 4,902 gross (3,857 net) identified drilling locations represent over 30 years of drilling inventory based on our expected 2013 drilling program. We view this drilling inventory as de-risked because the drilling locations were selected based on our extensive delineation drilling and production history in the area and well-established industry activity surrounding our acreage.

    Extensive horizontal development potential.  Operators have drilled hundreds of horizontal wells in the Wolfcamp, Cline and Mississippian formations in the Midland Basin, including numerous horizontal wells offsetting our acreage, and are continuing to accelerate horizontal drilling activity. Multiple Wolfcamp formations are prevalent across our entire leasehold position, and the Cline and Mississippian formations are present across portions of our leasehold position. Based on vertical well control information from our operations and the operations of offset operators, we have initially identified 311 gross (272 net) horizontal drilling locations in the Wolfcamp A formation, 357 gross (317 net) horizontal drilling locations in the Wolfcamp B formation, 133 gross (125 net) horizontal drilling locations in the Wolfcamp C formation,

 

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      227 gross (193 net) horizontal drilling locations in the Cline formation and 51 gross (24 net) horizontal drilling locations in the Mississippian formation. In addition, the subsurface data we have collected from our vertical drilling program also supports the potential for additional horizontal drilling in other formations, including the Strawn and Atoka formations. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify additional horizontal drilling locations. Our vertical drilling has been designed to preserve these future horizontal drilling opportunities and optimize hydrocarbon recovery rates on our acreage. Beginning in the second half of 2013, we intend to supplement our vertical drilling with horizontal drilling in circumstances where we believe that horizontal drilling should offer competitive rates of return.

    Large, concentrated acreage position with significant operational control.  Substantially all of our acreage is located in three counties in the Midland Basin. Our properties are characterized by large, contiguous acreage blocks, which has enabled us to implement more efficient and cost-effective operating practices and to capture economies of scale, including our installation of centralized production and fluid handling facilities, lowering of rig mobilization times and procurement of better vendor services. We seek to operate our properties so that we can continue to implement these efficient operating practices and control all aspects of our development program, including the selection of specific drilling locations, the timing of the development and the drilling and completion techniques used to efficiently develop our significant resource base. As of December 31, 2012, we operated approximately 99% of our proved reserves.

Recent Developments

    Our Capital Restructuring Program

        In the first quarter of 2013, we commenced a plan to enhance our overall capital structure and liquidity, including the execution of our amended and restated credit agreement in March 2013 that extends the maturity date of our reserve based lending facility to 2018. On April 17, 2013, we issued $500 million of 73/8% senior notes due 2021 and used most of the net proceeds from the offering to reduce the outstanding borrowings under our credit agreement and repay in full and terminate our former second lien term loan, thereby extending a large portion of our then-existing debt maturity to 2021. This offering represents a continuation of our plan, as we intend to apply the estimated proceeds of this offering to further reduce the outstanding borrowings under our credit agreement, provide additional liquidity for use in our drilling program and for general corporate purposes, including potential acquisitions.

    Second Quarter 2013 Drilling and Production

        During the three months ended June 30, 2013, we continued to execute our drilling program, spudding 45 vertical Wolfberry wells, of which 20 are currently producing, 7 are currently being drilled and 18 are waiting to be completed. Our average daily production volumes during the second quarter of 2013 were 6.5 MBbls/D of oil, 12.8 MMcf/D of natural gas and 2.5 MBbls/D of NGLs, or 11.1 MBOE/D in total. This represents an increase of 12% above our average daily production volumes for the first quarter of 2013 and an increase of 68% above our average daily production volumes for the second quarter of 2012.

    Hedge Portfolio

        Currently, we have oil swaps covering: 7,000 Bbls/D at a weighted-average price of $94.93 per Bbl for the remainder of 2013; 7,950 Bbls/D at a weighted-average price of $92.67 per Bbl for 2014; and

 

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1,300 Bbls/D at a weighted-average price of $93.18 per Bbl for 2015. We also have oil collars covering 150 Bbls/D for 2013 containing floors of $75.00 per Bbl and ceilings of $105.95 per Bbl.

2013 Capital Budget

        In 2013, we plan to invest $317 million of development capital, including $15 million for infrastructure, leasing and capitalized workovers, and drill 162 gross (150 net) vertical Wolfberry wells. We also plan to invest $33 million of development capital to drill 4 gross (4 net) horizontal Wolfcamp wells.

        In Howard, we plan to invest $155 million and drill 89 gross (82 net) wells. This includes 25 gross (23 net) PUD locations to be drilled through the Atoka/Mississippian formations at depths of approximately 9,900 feet. Our EURs per well for Howard PUD locations to be drilled through the Atoka/Mississippian formations average 141 MBOE as estimated by CG&A in our proved reserve report as of December 31, 2012. In addition, we plan to drill 64 gross (59 net) unproved locations through the Atoka/Mississippian formations.

        In Midland & Other, we plan to invest $95 million and drill 44 gross (42 net) wells. This includes 19 gross (19 net) PUD locations to be drilled through the Strawn/Atoka formations at depths of approximately 11,300 feet. Our EURs per well for Midland & Other PUD locations to be drilled through the Strawn/Atoka formations average 208 MBOE as estimated by CG&A in our proved reserve report as of December 31, 2012. In addition, we plan to drill 25 gross (23 net) unproved locations through the Strawn/Atoka formations.

        In Glasscock, we plan to invest $52 million and drill 29 gross (26 net) wells. This includes 8 gross (7 net) PUD locations to be drilled through the Atoka formation at depths of approximately 10,150 feet. Our EURs per well for Glasscock PUD locations to be drilled through the Atoka formation average 118 MBOE as estimated by CG&A in our proved reserve report as of December 31, 2012. In addition, we plan to drill 21 gross (19 net) unproved locations through the Atoka formation.

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" and "Cautionary Note Regarding Forward-Looking Statements."

Organizational Structure

        Athlon Energy Inc. is a holding company and its sole assets are controlling equity interests in Athlon Holdings LP and its subsidiaries. Athlon Energy Inc. operates and controls all of the business and affairs and consolidates the financial results of Athlon Holdings LP and its subsidiaries. Prior to our reorganization in April 2013, Apollo Investment Fund VII, L.P. and its parallel funds (the "Apollo Funds"), members of our management team and certain employees owned all of the Class A limited partner interests in Athlon Holdings LP and members of our management team and certain employees owned all of the Class B limited partner interests in Athlon Holdings LP. In the reorganization, the Apollo Funds entered into a number of distribution and contribution transactions pursuant to which the Apollo Funds exchanged their Class A limited partner interests in Athlon Holdings LP for common stock of Athlon Energy Inc. The remaining holders of Class A limited partner interests in Athlon Holdings LP have not exchanged their interests in the reorganization transactions. In addition, the holders of the Class B limited partner interests in Athlon Holdings LP exchanged their interests for common stock of Athlon Energy Inc. Upon closing of this offering, the limited partnership agreement of Athlon Holdings LP will be amended and restated to, among other things, modify Athlon Holdings

 

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LP's capital structure by replacing its different classes of interests with a single new class of units that we refer to as the "New Holdings Units." The members of our management team and certain employees that hold Class A limited partner interests of Athlon Holdings LP will own New Holdings Units and will enter into an exchange agreement under which (subject to the terms of the exchange agreement) they will have the right, under certain circumstances, to exchange their New Holdings Units for shares of common stock of Athlon Energy Inc. on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications. All other New Holdings Units will be held by Athlon Energy Inc. Please read "Corporate Reorganization" and "Certain Relationships and Related Party Transactions—Exchange Agreement."

        The diagram below sets forth our simplified organizational structure after our corporate reorganization and this offering. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us. The ownership percentages after this offering are based on an estimated valuation of Athlon using an assumed initial public offering price of $19.00 per share, the midpoint of the price range set forth on the cover page of this propsectus.

GRAPHIC


1
The Apollo Funds and the public stockholders will hold 65.8% and 22.1% of our shares of common stock, respectively, if the underwriters exercise in full their option to purchase additional shares of common stock from the Apollo Funds.

2
Borrowing base of $320 million as of July 22, 2013.

3
Co-Issuer of our 73/8% senior notes due 2021.

4
Guarantors of our credit agreement and 73/8% senior notes due 2021.

 

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Principal Stockholders

        Our principal stockholders are the Apollo Funds. The Apollo Funds are affiliates of Apollo Global Management, LLC (together with its subsidiaries, "Apollo").

        Apollo, founded in 1990, is a leading global alternative investment manager with offices in New York, Los Angeles, Houston, London, Frankfurt, Luxembourg, Singapore, Mumbai and Hong Kong. As of March 31, 2013, Apollo had assets under management of over $114 billion in private equity, credit-oriented capital markets and real estate funds invested across a core group of nine industries where Apollo has considerable knowledge and resources. Apollo's team of more than 250 seasoned investment professionals possesses a broad range of transactional, financial, managerial and investment skills, which has enabled the firm to deliver strong long-term investment performance throughout expansionary and recessionary economic cycles.

        Upon completion of this initial public offering and based on an estimated valuation of Athlon using an assumed initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), the Apollo Funds will beneficially own approximately 68.6% of our common stock (or approximately 65.8% if the underwriters' option to purchase additional shares of common stock from the Apollo Funds is exercised in full). We are also a party to certain other agreements with the Apollo Funds and certain of their affiliates. For a description of these agreements, please read "Certain Relationships and Related Party Transactions."

Corporate Information

        Our principal executive offices are located at 420 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102, and our telephone number is (817) 984-8200. Our website is www.athlonenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein 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, we will not be required to:

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

    comply with any new requirements adopted by the Public Company Accounting Oversight Board, 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 stockholder advisory votes on executive compensation.

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

    when we have $1.0 billion or more in annual revenues;

    when we have at least $700 million in market value of our common equity securities held by non-affiliates as of any June 30;

    when we issue more than $1.0 billion of non-convertible debt over a rolling three-year period; or

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

        As an emerging growth company, we can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we have chosen to "opt out" of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. This decision is irrevocable.

 

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THE OFFERING

Common stock offered by Athlon Energy Inc.    15,789,474 shares.

Common stock to be outstanding after the offering

 

82,122,646 shares.

New Holdings Units to be outstanding after the offering

 

83,984,689 units (1,862,043 of which will be exchangeable for 1,862,043 shares of our common stock).

Over-allotment option

 

The underwriters have a 30-day option to purchase 2,368,421 shares of common stock from the Apollo Funds if the underwriters sell more than 15,789,474 shares in this offering.

Use of proceeds

 

We expect to receive approximately $278.5 million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting estimated underwriting discounts and commissions and estimated offering expenses. Each $1.00 decrease in the public offering price would decrease our net proceeds by approximately $14.9 million. We intend to use the net proceeds from this offering to purchase newly issued New Holdings Units from Athlon Holdings LP, which would subsequently use the net proceeds to repay outstanding indebtedness under our credit agreement, provide additional liquidity for use in our drilling program and for general corporate purposes, including potential acquisitions. We will not receive any proceeds from sales by the Apollo Funds, including pursuant to the underwriters' option to purchase additional shares of common stock.

 

 

Affiliates of certain of the underwriters are lenders under our credit agreement and, accordingly, will receive a portion of the net proceeds from this offering. Please read "Use of Proceeds" and "Underwriting (Conflicts of Interest)."

Dividend policy

 

We do not anticipate paying any cash dividends on our common stock. In addition, our credit agreement and the indenture governing our senior notes place certain restrictions on our ability to pay cash dividends. Please read "Dividend Policy."

Risk factors

 

You should carefully read and consider the information beginning on page 18 of this prospectus set forth under the heading "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our common stock.

Listing and trading symbol

 

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

 

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Conflicts of interest   Apollo Global Securities, LLC is an affiliate of Apollo, our controlling stockholder. Since Apollo beneficially owns more than 10% of our outstanding common stock, a "conflict of interest" is deemed to exist under Rule 5121(f)(5)(B) of the Conduct Rules of the Financial Industry Regulatory Authority, or FINRA. In addition, if the Apollo Funds sell shares of common stock in this offering, the Apollo Funds, as selling stockholders, will likely receive more than 5% of the net proceeds of this offering, a "conflict of interest" also exists under Rule 5121(f)(5)(C)(ii). Accordingly, this offering will be made in compliance with the applicable provisions of Rule 5121. Since Apollo is not primarily responsible for managing this offering, the appointment of a "qualified independent underwriter" is not required pursuant to Rule 5121(a)(1). As such, any underwriter that has a conflict of interest pursuant to Rule 5121 will not confirm sales to accounts in which it exercises discretionary authority without the prior written consent of the customer. Please read "Underwriting (Conflicts of Interest)."

        The information above excludes 8,400,000 shares of common stock initially reserved for issuance under the Athlon Energy Inc. 2013 Incentive Award Plan (which amount may be increased each year in accordance with the terms of the plan).

        If the New Holdings Units subject to the terms of the exchange agreement were exchanged in full upon completion of this offering for shares of our common stock, there would be a total of 83,984,689 shares of our common stock outstanding, 18.8% of which would be owned by purchasers in this offering (assuming the option to purchase additional shares of common stock from the Apollo Funds is not exercised).

        If this offering is priced above the assumed initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover page of this prospectus) or if more than the number of shares set forth on the cover page of this prospectus are sold, then we may sell only such number of shares (the "threshold number") as is necessary to achieve gross proceeds from this offering to us of $300 million, and the Apollo Funds may sell a number of shares equal to the difference between the threshold number and the number of shares sold in this offering.

 

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SUMMARY CONSOLIDATED FINANCIAL, RESERVE AND OPERATING DATA

        The following summary consolidated financial, reserve and operating data of Athlon Holdings LP, our accounting predecessor, should be read in conjunction with, and are qualified by reference to, "Selected Historical Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and notes thereto included elsewhere in this prospectus.

        We derived the summary historical consolidated balance sheets data, statements of operations data and statements of cash flow data as of and for the years ended December 31, 2011 and 2012 of Athlon Holdings LP from the audited consolidated financial statements of Athlon Holdings LP, which are included elsewhere in this prospectus. We derived the summary historical consolidated balance sheet data as of March 31, 2013 and the historical consolidated statements of operations data and statements of cash flow data for the three months ended March 31, 2013 and 2012 of Athlon Holdings LP from the unaudited consolidated financial statements of Athlon Holdings LP, which are included elsewhere in this prospectus.

        The summary unaudited pro forma consolidated statements of operations data for the three months ended March 31, 2013 and for the year ended December 31, 2012 has been prepared to give pro forma effect to (i) our senior notes offering in April 2013, (ii) the reorganization transactions described under "Corporate Reorganization" and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2012. The summary unaudited pro forma consolidated balance sheet data as of March 31, 2013 has been prepared to give pro forma effect to these transactions as if they had been completed as of March 31, 2013. These data are subject and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the senior notes offering, the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

 

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Summary Consolidated Financial Data

 
   
   
  Historical Athlon Holdings LP  
 
  Pro Forma Athlon Energy Inc.  
 
  Three months
ended
March 31,
  Year ended
December 31,
 
 
  Three months
ended
March 31,
2013
   
 
 
  Year ended
December 31,
2012
 
 
  2013   2012   2012   2011  
 
  (unaudited)
  (unaudited)
   
   
 
 
  (in thousands, except per share data)
 

Consolidated Statements of Operations Data:

                                     

Revenues:

                                     

Oil

  $ 45,659   $ 128,081   $ 45,659   $ 27,433   $ 128,081   $ 51,193  

Natural gas

    3,367     8,415     3,367     1,448     8,415     3,521  

NGLs

    5,720     20,615     5,720     4,351     20,615     10,967  
                           

Total revenues

    54,746     157,111     54,746     33,232     157,111     65,681  
                           

Expenses:

                                     

Production:

                                     

Lease operating

    7,237     25,503     7,237     4,699     25,503     13,328  

Production, severance and ad valorem taxes

    3,694     10,438     3,694     2,350     10,438     4,727  

Depletion, depreciation and amortization        

    18,053     54,456     18,053     9,614     54,456     19,747  

General and administrative

    3,282     9,678     3,282     2,597     9,678     7,724  

Acquisition costs

    57     876     57         876     9,519  

Derivative fair value loss (gain)

    6,849     (9,293 )   6,849     22,711     (9,293 )   7,959  

Other operating

    194     562     194     130     562     404  
                           

Total expenses

    39,366     92,220     39,366     42,101     92,220     63,408  
                           

Operating income (loss)

    15,380     64,891     15,380     (8,869 )   64,891     2,273  

Interest expense

    9,976     40,590     4,474     1,495     9,949     2,932  
                           

Income (loss) before income taxes

    5,404     24,301     10,906     (10,364 )   54,942     (659 )

Income tax provision (benefit)

    2,021     9,086     27     (364 )   1,928     470  
                           

Consolidated net income (loss)

    3,383     15,215     10,879     (10,000 )   53,014     (1,129 )

Less: net income (loss) attributable to noncontrolling interest

    118     529                  
                           

Net income (loss) attributable to stockholders

  $ 3,265   $ 14,686   $ 10,879   $ (10,000 ) $ 53,014   $ (1,129 )
                           

Net income (loss) per common share:

                                     

Basic

  $ 0.05   $ 0.22                          

Diluted

  $ 0.05   $ 0.22                          

Weighted average common shares outstanding:

                                     

Basic

    66,333     66,333                          

Diluted

    68,195     68,195                          

Consolidated Statements of Cash Flows Data:

                                     

Cash provided by (used in):

                                     

Operating activities

              $ 30,397   $ 20,723   $ 95,302   $ 18,872  

Investing activities

                (90,560 )   (58,498 )   (347,259 )   (465,475 )

Financing activities

                54,671     12,982     228,798     471,627  

Consolidated Balance Sheets Data (at period end):

                                     

Cash and cash equivalents

  $ 275,103         $ 3,379         $ 8,871   $ 32,030  

Total assets

    1,197,926           916,535           852,298     561,823  

Total debt

    500,000           416,426           362,000     170,000  

Total equity

    612,848           433,330           420,877     327,452  

Other Financial Data:

                                     

Adjusted EBITDA1

  $ 40,669   $ 111,160   $ 40,669   $ 21,171   $ 111,160   $ 39,094  

Development capital

                71,791     49,241     276,182     89,232  

1
Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measures."

 

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Summary Reserve Data

        The following table presents summary data with respect to our estimated net proved reserves as of the dates indicated. The reserve estimates presented in the table below are based on proved reserve reports prepared by CG&A, our independent petroleum engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of December 31, 2012 and 2011, please read CG&A's proved reserve reports, which have been filed as exhibits to the registration statement of which this prospectus is a part.

 
  December 31,  
 
  2012   2011  

Reserves Data1:

             

Estimated proved reserves:

             

Oil (MBbls)

    49,423     25,972  

Natural gas (MMcf)

    103,683     51,560  

NGLs (MBbls)

    19,275     11,549  

Total estimated proved reserves (MBOE)

    85,979     46,114  

Proved developed reserves (MBOE)

    25,698     13,496  

% proved developed

    30 %   29 %

Proved undeveloped reserves (MBOE)

    60,281     32,618  

PV-10 of proved reserves (in millions)2

  $ 866.6   $ 591.4  

Standardized Measure (in millions)3

  $ 850.9   $ 581.2  

1
Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $94.71 per Bbl for oil and $2.75 per Mcf for natural gas at December 31, 2012 and $96.19 per Bbl for oil and $4.11 per Mcf for natural gas at December 31, 2011. These prices were adjusted by lease for quality, transportation fees, historical geographic differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

2
PV-10 is a non-GAAP financial measure and generally differs significantly from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of federal income taxes on future net revenues. As of December 31, 2012 and 2011, our accounting predecessor was a limited partnership not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our Standardized Measure because taxable income was passed through to its partners. However, the PV-10 and the Standardized Measure differ as a result of the Texas margin tax. Had we been a Subchapter C Corporation subject to federal income taxation, our Standardized Measure would have been $602.5 million and $428.5 million as of December 31, 2012 and 2011, respectively, on a pro forma basis. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Please read "—Non-GAAP Financial Measures."

3
Standardized Measure represents the present value of estimated future cash inflows from proved reserves, less future development, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.

Non-GAAP Financial Measures

    Adjusted EBITDA

        We include in this prospectus the non-GAAP financial measure Adjusted EBITDA. We provide a reconciliation of Adjusted EBITDA to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

        We define Adjusted EBITDA as consolidated net income (loss):

    Plus:

    Interest expense;

    Income tax provision;

    Depreciation, depletion and amortization;

    Acquisition costs;

    Advisory fees;

 

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    Non-cash equity-based compensation expense;

    Derivative fair value loss;

    Net derivative settlements received adjusted for recovered premiums;

    Accretion of discount on asset retirement obligations;

    Impairment of oil and natural gas properties, if any; and

    Other non-cash operating items.

    Less:

    Interest income;

    Income tax benefit;

    Derivative fair value gain; and

    Net derivative settlements paid adjusted for recovered premiums.

        Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our consolidated financial statements, such as investors, lenders under our credit agreement, commercial banks, research analysts and others, to assess:

    the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

    our operating performance and return on capital as compared to those of other companies in the upstream energy sector, without regard to financing or capital structure; and

    the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

        The GAAP measures most directly comparable to Adjusted EBITDA are cash flows provided by operating activities and consolidated net income (loss). Adjusted EBITDA should not be considered as an alternative to cash flows provided by operating activities or consolidated net income (loss). Adjusted EBITDA may not be comparable to similar measures used by other companies. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Adjusted EBITDA has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, performance measures calculated in accordance with GAAP. Some of these limitations are:

    certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historical costs of depreciable assets;

    Adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

    Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

    although depreciation, depletion and amortization are non-cash charges, the assets being depreciated, depleted and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements; and

    our computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

        Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into their decision-making process.

 

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        The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of consolidated net income (loss):

 
   
   
  Historical Athlon Holdings LP  
 
  Pro Forma Athlon Energy Inc.  
 
  Three months
ended
March 31,
  Year ended
December 31,
 
 
  Three months
ended
March 31,
2013
   
 
 
  Year ended
December 31,
2012
 
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Consolidated net income (loss)

  $ 3,383   $ 15,215   $ 10,879   $ (10,000 ) $ 53,014   $ (1,129 )

Interest expense

    9,976     40,590     4,474     1,495     9,949     2,932  

Income tax provision (benefit)

    2,021     9,086     27     (364 )   1,928     470  

Depreciation, depletion and amortization

    18,053     54,456     18,053     9,614     54,456     19,747  

Acquisition costs

    57     876     57         876     9,519  

Advisory fees1

    405     493     405     213     493     411  

Non-cash equity-based compensation

    48     152     48     58     152     106  

Derivative fair value loss (gain)2

    6,849     (9,293 )   6,849     22,711     (9,293 )   7,959  

Net derivative settlements paid adjusted for recovered premiums3

    (318 )   (1,074 )   (318 )   (2,698 )   (1,074 )   (2,734 )

Accretion4

    149     478     149     106     478     344  

Other non-cash operating items5

    46     181     46     36     181     1,469  
                           

Adjusted EBITDA

  $ 40,669   $ 111,160   $ 40,669   $ 21,171   $ 111,160   $ 39,094  
                           

1
Represents the annual advisory fee paid to affiliates of Apollo pursuant to a Services Agreement. The Services Agreement will be terminated in connection with this offering. Please read "Certain Relationships and Related Party Transactions."

2
Represents total derivative loss (gain) reported in our consolidated statements of operations.

3
The purpose of this adjustment is to reflect derivative gains and losses on a cash basis in the period the derivative settled rather than the period the gain or loss was recognized for GAAP. It represents the net cash payments on derivative contracts for all commodity derivatives that were settled during the respective periods, excluding any portion representing a recovery of cost (i.e., premiums paid).

4
Represents the non-cash accretion of discount on asset retirement obligations.

5
Represents deferred rent expense and non-cash LOE.

        The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of cash flows provided by operating activities:

 
  Historical Athlon Holdings LP  
 
  Three months
ended
March 31,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Adjusted EBITDA

  $ 40,669   $ 21,171   $ 111,160   $ 39,094  

Changes in operating assets and liabilities

    (5,579 )   1,102     (5,639 )   (6,510 )

Acquisition costs

    (57 )       (876 )   (9,519 )

Non-cash LOE

                (1,159 )

Cash interest expense

    (4,231 )   (1,337 )   (8,850 )   (2,623 )

Advisory fees1

    (405 )   (213 )   (493 )   (411 )
                   

Cash flows provided by operating activities

  $ 30,397   $ 20,723   $ 95,302   $ 18,872  
                   

1
Represents the annual advisory fee paid to affiliates of Apollo pursuant to a Services Agreement. The Services Agreement will be terminated in connection with this offering. Please read "Certain Relationships and Related Party Transactions."

 

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    PV-10

        PV-10 is a non-GAAP financial measure and is derived from Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the relative monetary significance of our properties regardless of tax structure. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our proved reserves to other companies. We use this measure when assessing the potential return on investment related to our oil, natural gas and NGL properties. However, PV-10 is not equal to, nor a substitute for, the Standardized Measure of discounted future net cash flows. Our PV-10 and the Standardized Measure of discounted future net cash flows do not purport to present the fair value of our proved reserves. The following table provides a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of December 31, 2012 and 2011:

 
  As of
December 31,
 
 
  2012   2011  
 
  (in millions)
 

PV-10 of proved reserves

  $ 866.6   $ 591.4  

Present value of future income tax discounted at 10%

    (15.7 )   (10.2 )
           

Standardized Measure

  $ 850.9   $ 581.2  
           

Summary Operating Data

        The following table sets forth summary data with respect to our production results, average realized prices and certain expenses on a per BOE basis for the periods presented:

 
  Three months
ended
March 31,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  

Total production volumes:

                         

Oil (MBbls)

    542     276     1,457     556  

Natural gas (MMcf)

    1,030     534     3,163     1,017  

NGLs (MBbls)

    183     102     595     239  

Combined (MBOE)

    896     468     2,579     964  

Average daily production volumes:

                         

Oil (Bbls/D)

    6,023     3,036     3,981     1,523  

Natural gas (Mcf/D)

    11,446     5,871     8,641     2,786  

NGLs (Bbls/D)

    2,028     1,125     1,625     654  

Combined (BOE/D)

    9,959     5,140     7,047     2,641  

Average realized prices:

                         

Oil ($/Bbl) (excluding impact of cash settled derivatives)

  $ 84.23   $ 99.29   $ 87.90   $ 92.08  

Oil ($/Bbl) (after impact of cash settled derivatives)

    60.73     65.28     60.50     65.29  

Natural gas ($/Mcf)

    3.27     2.71     2.66     3.46  

NGLs ($/Bbl)

    31.34     42.48     34.65     45.96  

Combined ($/BOE) (excluding impact of cash settled derivatives)

    61.08     71.05     60.91     68.13  

Combined ($/BOE) (after impact of cash settled derivatives)

    83.65     89.53     87.16     87.16  

Expenses (per BOE):

                         

Lease operating

  $ 8.07   $ 10.05   $ 9.89   $ 13.82  

Production, severance and ad valorem taxes

    4.12     5.03     4.05     4.90  

Depletion, depreciation and amortization

    20.14     20.55     21.11     20.48  

General and administrative

    3.73     5.55     3.75     8.01  

 

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RISK FACTORS

        An investment in our common stock involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common stock. Our business, financial condition and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we consider immaterial also may adversely affect us.


Risks Related to the Oil and Natural Gas Industry and Our Business

Our business is difficult to evaluate because we have a limited operating history.

        Athlon Holdings LP was formed in July 2011 and became the sole owner of Athlon Energy LP, which began operating our first properties after acquiring them in January 2011. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

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. In addition, the application of new techniques for us such as horizontal drilling, which we have not previously employed, may make it more difficult to accurately estimate these costs. 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;

    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 and natural gas 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.

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        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.

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

        We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions 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.

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. 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.

As of May 31, 2013, approximately 45% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our reserves and future production and, therefore, our future cash flow and income.

        As of May 31, 2013, approximately 45% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of hydrocarbons regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our reserves.

        The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of reserves. In 2012, our total development capital was approximately $276 million and expenditures for leasehold interest and property acquisitions were approximately $81 million. Our 2013 development capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is approximately $350 million.

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To date, we have financed capital expenditures primarily with funding from the Apollo Funds, our equity sponsor, borrowings under our credit agreement and cash flows from operations. Notwithstanding prior contributions to us by the Apollo Funds or their affiliates, you should not assume that any of them will provide any debt or equity funding to us in the future.

        In the near term, we intend to finance our capital expenditures with cash flows from operations and borrowings under our credit agreement. Our cash flows from operations and access to capital are subject to a number of variables, including:

    our proved reserves;

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

    the prices at which our production is sold;

    the levels of our operating expenses; and

    our ability to acquire, locate and produce new reserves.

        We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2013 could exceed our budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint ventures, production payment financings, sales of assets, private or public offerings of debt or equity securities or other means. Our ability to access the private and public debt or equity markets is dependent upon a number of factors outside our control, including oil and natural gas prices as well as economic conditions in the financial markets. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

        Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. In addition, our ability to access the private and public debt or equity markets is dependent upon a number of factors outside our control, including oil and natural gas prices as well as economic conditions in the financial markets. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

        If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our reserves, or may be otherwise unable to implement our development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our success depends on finding, developing or acquiring additional reserves. Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

        Our future oil and natural gas reserves and production, and therefore our cash flows and income, highly depend on our ability to find, develop or acquire additional reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing

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proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of reserves. We may not have sufficient resources to undertake our exploration, development and production activities. In addition, the acquisition of reserves, our exploratory projects and other replacement activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing commodity prices increase, our finding costs for additional reserves could also increase.

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. From the time we began operations in January 2011 through May 31, 2013, we have drilled a total of 230 gross (220 net) wells and participated in an additional 8 gross (3 net) non-operated wells. In total, 216 gross (202 net) of these wells were completed as producing wells and 3 gross (3 net) wells were abandoned as dry holes. At May 31, 2013, 19 gross (19 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.

Our identified potential 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 May 31, 2013, we had identified 2,298 gross (1,797 net) potential vertical drilling locations on our existing acreage based on 40-acre spacing and an additional 2,604 gross (2,060 net) potential vertical drilling locations based on 20-acre spacing. Only 597 gross (560 net) of these potential vertical drilling locations were attributed to PUDs in our December 31, 2012 reserve report. These drilling locations, including those without PUDs, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, commodity prices, lease expirations, our ability to secure rights to drill at deeper formations, costs and drilling results.

        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 oil or natural gas reserves in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre spacing will produce at the same rates as those on 40-acre spacing. The use of reliable technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas reserves will be present or, if present, whether oil or natural gas reserves will be present in sufficient quantities 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 the Permian Basin may not be indicative of future or long-term production rates.

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        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.

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

        Approximately 70% of our total proved reserves at December 31, 2012 were PUDs and may not be ultimately developed or produced. Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the independent petroleum engineering firm's proved reserve report assumes that substantial capital expenditures are required to develop such 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 PUDs 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 PUDs.

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 May 31, 2013, we had leases representing 9,639 gross (7,653 net) acres scheduled to expire in 2013, 5,362 gross (4,257 net) acres scheduled to expire in 2014, 9,213 gross (7,363 net) acres scheduled to expire in 2015, 27,224 gross (21,049 net) acres scheduled to expire in 2016 and no 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 three-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.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations.

        The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand for oil and natural gas. In accordance with customary industry practice, we rely on independent third-party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. We are currently operating seven vertical drilling rigs across our

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properties and we expect to take delivery of our first horizontal rig in the third quarter of 2013 and our second horizontal rig in the second quarter of 2014. In 2014, we intend to expand to an eight-rig vertical drilling program. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, drilling rig crews and other personnel, trucking services, tubulars, fracking and completion services and production equipment, including equipment and personnel related to horizontal drilling activities, could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

        Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing commodity prices. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

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

    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 oil and natural gas 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 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, including U.S. military operations in the Middle East;

    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 and natural gas price movements with any certainty. For example, during the past five years, the NYMEX prompt month contract price for WTI has ranged from a low of $33.87 per Bbl in December 2008 to a high of $145.29 per Bbl in July 2008, and the Henry Hub prompt month contract price of natural gas has ranged from a low of $1.91 per MMBtu in April 2012 to a high of $13.58 per MMBtu

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in July 2008. During the first quarter of 2013, WTI prompt month contract ranged from $90.12 to $97.94 per Bbl and the Henry Hub prompt month contract price of natural gas ranged from $3.11 to $4.07 per MMBtu. During 2012, WTI prompt month contract ranged from $77.69 to $109.77 per Bbl and the Henry Hub prompt month contract price of natural gas ranged from $1.91 to $3.90 per MMBtu. On March 31, 2013, the WTI prompt month contract price for crude oil was $97.23 per Bbl and the Henry Hub prompt month contract price of natural gas was $4.02 per MMBtu. Any substantial decline in commodity prices will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our reserves.

        As of December 31, 2012, NGLs comprised 22% of our estimated proved reserves and accounted for 23% of our 2012 production at an average price of $34.65 per Bbl, a 25% drop in average price from the prior year. Further, realized NGL prices have decreased principally due to significant supply. The terms of our sale contracts allow purchasers of our production to decline to purchase our produced ethane and instead pay dry natural gas prices for the ethane that we produce in the gas stream. 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.

        Substantially all of our production is sold to purchasers under contracts with market-based prices. Moreover, all of our oil contracts include the Midland-Cushing differential (the difference between Midland WTI and Cushing WTI), which widened in 2012 and in early 2013 due to difficulty transporting oil production from the Permian Basin to the Gulf Coast refineries as a result of lack of logistics and infrastructure. The Midland-Cushing differential has since narrowed. We may experience differentials to NYMEX in the future, which may be material. Lower oil, natural gas and NGL prices will reduce our cash flows and the present value of our reserves. If oil, natural gas and NGL prices deteriorate, we anticipate that the borrowing base under our credit agreement, which is revised periodically, may be reduced, which would negatively impact our borrowing ability. Additionally, prices could reduce our cash flows to a level that would require us to borrow to fund our current or future capital budgets. Lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. Substantial decreases in oil, natural gas and NGL prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. As a result, a substantial or extended decline in oil, natural gas or NGL prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We have entered into oil derivative contracts and may in the future enter into additional commodity derivative contracts for a portion of our production, which may result in future cash payments or prevent us from receiving the full benefit of increases in commodity prices.

        We use commodity derivative contracts to reduce price volatility associated with certain of our oil sales. Under these contracts, we receive a fixed price per Bbl of oil and pay a floating market price per Bbl of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, some of the commodity derivative contracts we utilize are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil. In addition, our credit agreement limits the aggregate notional volume of commodities that can be covered under commodity derivative contracts we can enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. As of March 31, 2013, we have oil swaps covering: 6,000 Bbls/D at a weighted-

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average price of $94.66 per Bbl for 2013; 5,950 Bbls/D at a weighted-average price of $92.76 per Bbl for 2014; and 1,300 Bbls/D at a weighted-average price of $93.18 per Bbl for 2015. We also have oil collars covering 150 Bbls/D for 2013 containing floors of $75.00 per Bbl and ceilings of $105.95 per Bbl. Our policy has been to hedge a significant portion of our estimated oil production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current commodity prices. Accordingly, our price hedging strategy may not protect us from significant declines in commodity prices received for our future production, whether due to declines in prices in general or to widening differentials we experience with respect to our products. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our revenues becoming more sensitive to commodity price changes.

        In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our commodity derivative contracts.

Our commodity derivative contracts expose us to counterparty credit risk.

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

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

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

        In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from purchasers of our oil and natural gas production. For 2012, three purchasers accounted for more than 10% of our revenues: Pecos Gathering & Marketing (43%); Occidental Petroleum Corporation (29%); and DCP Midstream (12%). This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

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Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

        We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per BOE of production was $21.03 and $20.32 for 2012 and 2011, respectively. Total depletion expense for oil and natural gas properties was $54.2 million and $19.6 million for 2012 and 2011, respectively.

        The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved reserves, the excess capitalized costs are charged to expense.

        To date, we have not recorded any impairment on proved oil and natural gas properties. However, we may experience ceiling test write downs in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Impairment" for a more detailed description of our method of accounting.

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

        Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of reserves and assumptions concerning future commodity prices, production levels, EURs and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2012 and 2011 are based on proved reserve reports prepared by CG&A, our independent petroleum engineers. CG&A conducted a well-by-well review of all our properties for the periods covered by its proved reserve reports using information provided by us. Over time, we may make material changes to proved reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future commodity prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of proved reserves, the economically recoverable quantities of reserves attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of reserves we ultimately recover being different from our estimates.

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        The estimates of proved reserves as of December 31, 2012 and 2011 included in this prospectus were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12 months ended December 31, 2012 and 2011, respectively, in accordance with GAAP. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved acreage. The reserve estimates represent our net revenue interest in our properties.

        The timing of both our production and our incurrence of costs in connection with the development and production of reserves will affect the timing of actual future net cash flows from proved reserves.

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 Standardized Measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

        You should not assume that the Standardized Measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2012 and 2011, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

    actual prices we receive for oil and natural gas;

    actual cost of development and production expenditures;

    the amount and timing of actual production; and

    changes in governmental regulations or taxation.

        The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating Standardized Measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a limited partnership, our predecessor was not subject to federal taxation. Accordingly, our Standardized Measure does not provide for federal corporate income taxes because taxable income was passed through to its partners. As a corporation, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus which could have a material effect on the value of our reserves.

All of our properties are located in the Permian Basin, making us vulnerable to risks associated with operating in one geographic area.

        All of our producing properties are located in the Permian Basin. 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, availability of equipment, facilities, personnel or services market

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limitations or interruption of the processing or transportation of crude oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of oil and natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

We depend upon a limited number of significant purchasers for the sale of most of our production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the hydrocarbons we produce.

        The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon a limited number of significant purchasers for the sale of most of our production, and our contracts with those customers typically are on a month-to-month basis. The loss of these customers could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production.

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

        Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.

We may face unanticipated water and other waste disposal costs.

        We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas production operations. Productive zones frequently contain water that must be removed in order for the natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

        Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have

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to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

    we cannot obtain future permits from applicable regulatory agencies;

    water of lesser quality or requiring additional treatment is produced;

    our wells produce excess water;

    new laws and regulations require water to be disposed in a different manner; or

    costs to transport the produced water to the disposal wells increase.

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

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

We have incurred losses from operations during certain periods since our inception and may do so in the future.

        We incurred a net loss of $1.1 million for 2011, our first full year of operation, and we may incur net losses in the future. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop and acquire reserves. As a result, we may not be able to sustain profitability or positive cash flows provided by operating activities in the future.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

        Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. While horizontal drilling is a significant part of our growth strategy, we have not previously drilled a horizontal well and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have experience in horizontal drilling activities.

        Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not 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, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. We expect to face many of these similar risks when we commence our horizontal drilling program. In

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addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations.

        Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Our level of indebtedness may increase and reduce our financial flexibility.

        As of March 31, 2013, on a pro forma basis giving effect to our April 2013 senior notes offering and the application of the net proceeds therefrom, we would have had a total of $503.4 million in outstanding indebtedness and $264.1 million of borrowing capacity under our credit agreement. We may incur significant indebtedness in the future in order to make acquisitions or to develop our properties.

        Our level of indebtedness could affect our operations in several ways, including the following:

    a significant portion of our cash flows could be used to service our indebtedness;

    a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

    the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

    a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

    our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

    a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

    a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

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The agreements governing our indebtedness contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

        Our credit agreement and the indenture governing our senior notes contain restrictive covenants that limit our ability to, among other things:

    incur additional indebtedness;

    create additional liens;

    sell assets;

    merge or consolidate with another entity;

    pay dividends or make other distributions;

    engage in transactions with affiliates; and

    enter into certain commodity derivative contracts.

        In addition, our credit agreement requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be an event of default under the terms of such agreements, which could result in an acceleration of repayment.

        If we are unable to comply with the restrictions and covenants in our credit agreement or the indenture governing our senior notes, there could be an event of default. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests under our credit agreement, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our credit agreement or the indenture governing our senior notes, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our credit agreement or obtain needed waivers on satisfactory terms.

Our borrowings under our credit agreement expose us to interest rate risk.

        Our results of operations are exposed to interest rate risk associated with borrowings under our credit agreement, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the type of loan used and the amount of the loan outstanding in relation to the borrowing base. As of March 31, 2013, the weighted-average interest rate on outstanding borrowings under our credit agreement was approximately 2.5%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

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

        Under our credit agreement, which currently provides for a $320 million borrowing base, we are subject to collateral borrowing base redeterminations based on our proved reserves. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial condition, results of operations and cash flows.

We rely on a few key employees whose absence or loss could adversely affect our business.

        Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our management team, including our Chief Executive Officer, Robert C. Reeves, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain "key person" life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

        Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including 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 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 and repairs to resume operations.

        We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (1) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors' equipment while in their control and (2) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, natural gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.

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        In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

        Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the "occurrence" to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows. Please read "Business—Operational Hazards and Insurance" for a description of our insurance coverage.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our operating results and slow our growth.

        There is intense competition for acquisition opportunities in our industry and 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. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with these regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our results of operations and growth. Our financial condition and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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

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

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

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    a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

    a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

    the assumption of unknown liabilities, losses or costs for which we obtain no or limited indemnity or other recourse;

    the diversion of management's attention from other business concerns;

    an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and

    the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

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

        Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

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

        It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

        Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

        The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other

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products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing reserves.

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

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.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

        The marketability of our production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third-party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a

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significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our production and thereby cause a significant interruption in our operations.

        In the past we have been required to flare a portion of our natural gas production for a number of reasons, including the fact that (1) our well is not yet tied into the third-party gathering system, (2) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported or (3) our production is prorated due to high demand on the third-party gathering system. During the first quarter of 2013, we flared an average of approximately 2.0 MMcf/D, or 331 BOE/D, of natural gas, which included both residue gas and NGL production. We expect to continue flaring approximately 3.0 MMcf/D to 4.0 MMcf/D until further improvements can be made to certain gathering systems near our wells. These improvements are scheduled to come on line in mid-2013, although we cannot guarantee that this will be the case.

        Also, the transfer of our oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our access to transportation options, including trucks owned by third parties, 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. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production-related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of our production, would adversely affect our financial condition and results of operations.

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

        Our operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations, primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue for the foreseeable future. Please read "Business—Regulation" for a description of the laws and regulations that affect us.

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

        Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (the "SDWA") regulates the

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underground injection of substances through the Underground Injection Control ("UIC") program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The Environmental Protection Agency (the "EPA") however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as "Class II" UIC wells. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA commenced a study regarding the environmental effects of hydraulic fracturing activities. The EPA issued a Progress Report in December 2012 and a final draft is anticipated by 2014 for peer review and public comment. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA.

        Federal agencies are also considering additional regulation of hydraulic fracturing. On October 20, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations.

        On August 16, 2012, the EPA published final regulations under the federal Clean Air Act, as amended, (the "CAA") that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds ("VOCs") and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes 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 also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production 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 in 2013 that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. The U.S. Department of the Interior has also announced its intention to propose a new rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity and handling of flowback water.

        Several states, including Texas have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. We plan to use hydraulic fracturing extensively in connection with the development and production of certain of our oil and

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natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volume of reserves that we can economically recover, which could materially and adversely affect our revenues and results of operations.

        There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

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

        We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

        Under certain environmental laws that impose strict as well as joint and several liability, 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. In addition, the risk of accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. 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 oil and natural gas industry could

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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.

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

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

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

        The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010, and required the Commodities Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations implementing the legislation within 360 days from the date of enactment. In its rulemaking under the legislation, the CFTC proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated numerous final rules based on its proposals, it is not possible at this time to predict when the CFTC will finalize its proposed regulations or the effect of such regulations on our business. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. This legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation 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 legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to

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oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

        The U.S. President's Fiscal Year 2014 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period for certain geological and geophysical expenditures. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

        Many nations have agreed to limit emissions of "greenhouse gases" ("GHGs") pursuant to the United Nations Framework Convention on Climate Change, also known as the "Kyoto Protocol." Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are GHGs regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of GHGs. The EPA has adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it also became effective in January 2011. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.

        In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce GHG emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

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        Restrictions on GHG emissions that may be imposed in various states could adversely affect the oil and natural gas industry. While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how future laws or regulations addressing GHG emissions would impact our business.

        In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

        We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act as early as December 31, 2014. Section 404 requires that we document and test our internal control over financial reporting and issue management's assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify as an emerging growth company under the JOBS Act. We are evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

        We believe that the out-of-pocket costs, diversion of management's attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

        We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our independent registered public accounting firm will not identify material weaknesses in our internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our independent registered public accounting firm identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the stock price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Loss of our information and computer systems could adversely affect our business.

        We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such

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programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

        Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.


Risks Related to this Offering and Our Common Stock

Athlon Energy Inc.'s only material asset is its interest in Athlon Holdings LP, and Athlon Energy Inc. is accordingly dependent upon distributions from Athlon Holdings LP to pay taxes, make payments under the tax receivable agreement and pay dividends.

        Athlon Energy Inc. is a holding company and has no material assets other than its ownership of New Holdings Units in Athlon Holdings LP. Athlon Energy Inc. has no independent means of generating revenue. Athlon Energy Inc. intends to cause Athlon Holdings LP to make distributions to its unitholders, which include Athlon Energy Inc., members of our management team and certain employees, in an amount sufficient to cover all applicable taxes at assumed tax rates, payments under the tax receivable agreement and dividends, if any, declared by it. To the extent that Athlon Energy Inc. needs funds, and Athlon Holdings LP is restricted from making such distributions under applicable law or regulation or under the terms of its financing arrangements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

        Athlon Holdings LP entered into an amended and restated credit agreement dated as of March 19, 2013, which we refer to as our credit agreement. In addition, Athlon Holdings LP entered into an indenture dated as of April 17, 2013 governing its 73/8% senior notes due 2021. Each of these agreements includes a restricted payment covenant, which places certain restrictions on the ability of Athlon Holdings LP to make distributions to its unitholders, including Athlon Energy Inc.

Our largest stockholder controls a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

        Upon completion of this offering, assuming the Apollo Funds or their affiliates make no additional purchases of our common stock and based on an estimated valuation of Athlon using an assumed initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), the Apollo Funds will beneficially own in the aggregate approximately 68.6% of the combined voting power of our common stock (or approximately 65.8% if the underwriters option to purchase additional shares of common stock from the Apollo Funds is exercised in full). As a result, the Apollo Funds will be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. In addition, the

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stockholders agreement that we will enter into in connection with this offering will provide that, except as otherwise required by applicable law, if the Apollo Funds hold: (a) at least 50% of our outstanding common stock, they will have the right to designate no fewer than that number of directors that would constitute a majority of our Board of Directors; (b) at least 30% but less than 50% of our outstanding common stock, they will have the right to designate up to three director nominees; (c) at least 20% but less than 30% of our outstanding common stock, they will have the right to designate up to two director nominees; and (d) at least 10% but less than 20% of our outstanding common stock, they will have the right to designate up to one director nominee. The agreement also provides that if the size of our Board of Directors is increased or decreased at any time to other than seven directors, Apollo's nomination rights will be proportionately increased or decreased, respectively, rounded up to the nearest whole number. In addition, the agreement provides that if the Apollo Funds hold at least 30% of our outstanding common stock, we will cause any committee of our Board of Directors to include in its membership at least one of the Apollo Funds nominees, except to the extent that such membership would violate applicable securities laws or stock exchange or stock market rules. The interests of the Apollo Funds 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, the Apollo Funds would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of Apollo. These directors' duties as employees of Apollo may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest.

We expect to be a "controlled company" within the meaning of the NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements.

        Upon the closing of this offering, the Apollo Funds will continue to control a majority of our voting common stock. As a result, we expect to qualify as a "controlled company" within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, group or another company is a "controlled company" and may elect not to comply with certain NYSE corporate governance requirements, including:

    the requirement that a majority of our Board of Directors consists of independent directors;

    the requirement that we have a nominating and corporate governance 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 with a written charter addressing the committee's purpose and responsibilities; and

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

        Following this offering, we intend to utilize certain of these exemptions. As a result, we will not have a majority of independent directors nor will our nominating and corporate governance and compensation committees consist entirely of independent directors, and we will not be required to have an annual performance evaluation of the nominating and corporate governance and compensation committees. Please read "Management—Composition of Our Board of Directors." Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to such corporate governance requirements.

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The corporate opportunity provisions in our amended and restated certificate of incorporation could enable the Apollo Funds, our equity sponsor, 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 us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

    permits any of our stockholders, 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 any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (1) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (2) acted in bad faith or in a manner inconsistent with our best interests.

        As a result, the Apollo 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 the Apollo 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 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 the Apollo Funds or their affiliates, including pricing, duration or other terms of service, may not always be in our or our stockholders' best interests because the Apollo Funds may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, please read "—Our largest stockholder controls a significant percentage of our common stock, and their interests may conflict with those of our other stockholders."

We will incur increased costs as a result of being a public company, which may significantly affect our financial condition.

        As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with corporate governance requirements, including requirements under the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, particularly after we are no longer an "emerging growth company." We also expect these rules and regulations may make it more difficult and more expensive for us to obtain director and officer

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liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers.

        We will 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. Please read "—Risks Related to the Oil and Natural Gas Industry and Our Business—We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected."

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 intend to 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 will 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 remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates as of any June 30 or issue more than $1.0 billion of non-convertible debt over a rolling three-year period.

        Under the JOBS Act, "emerging growth companies" can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected not to avail ourselves of this exemption from new or revised accounting standards and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not "emerging growth 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.

There has been no public market for our common stock and if the price of our common stock fluctuates significantly, your investment could lose value.

        Prior to this offering, there has been no public market for our common stock. Although we have been approved to list our common stock on the NYSE, we cannot assure you that an active public market will develop for our common stock or that our common stock will trade in the public market subsequent to this offering at or above the initial public offering price. If an active public market for

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our common stock does not develop, the stock price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or "float" for our common stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock is less liquid than the stock of companies with broader public ownership and, as a result, the stock price of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The initial offering price, which will be negotiated between us and the underwriters, may not be indicative of the stock price for our common stock after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

    our quarterly or annual operating results;

    changes in our earnings estimates;

    investment recommendations by securities analysts following our business or our industry;

    additions or departures of key personnel;

    changes in the business, earnings estimates or market perceptions of our competitors;

    our failure to achieve operating results consistent with securities analysts' projections;

    changes in industry, general market or economic conditions; and

    announcements of legislative or regulatory change.

        The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

        Sales of substantial amounts of our common stock in the public market after this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. Please read "Shares Eligible for Future Sale." In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock. After this offering, we will have 82,122,646 shares of common stock outstanding, excluding awards under the Athlon Energy Inc. 2013 Incentive Award Plan and New Holdings Units that are exchangeable for shares of our common stock. All of the shares sold in this offering, except for any shares purchased by our affiliates, will be freely tradable.

        The Apollo Funds and our directors and executive officers will be subject to agreements that limit their ability to sell our common stock held by them. These holders cannot sell or otherwise dispose of any shares for a period of at least 180 days after the date of this prospectus without the prior written approval of Citigroup Global Markets Inc. However, these lock-up agreements are subject to certain specific exceptions, including transfers of common stock as a bona fide gift or by will or intestate succession and transfers to such person's immediate family or to a trust or to an entity controlled by such holder, provided that the recipient of the shares agrees to be bound by the same restrictions on sales. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

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        As soon as practicable after this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 8,400,000 shares of our common stock issued or reserved for issuance under the Athlon Energy Inc. 2013 Incentive Award Plan that we plan to adopt prior to the completion of this offering. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under our registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

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

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

        The Apollo Funds 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 180 days following the date of this prospectus. Citigroup Global Markets Inc., at any time and without notice, 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 will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of stock options granted to certain of our executive officers under their respective employment agreements.

        The initial public offering price is substantially higher than the pro forma net tangible book value per share of our outstanding common stock. As a result, you will experience immediate and substantial dilution of approximately $11.54 per share, representing the difference between our net tangible book value per share as of March 31, 2013 after giving effect to this offering and an assumed initial public offering price of $19.00 per share (which is the midpoint of the price range set forth on the cover page of the prospectus). A $1.00 decrease in the assumed initial public offering price of $19.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus) would decrease our net tangible book value per share after giving effect to this offering by $0.18 per share, and decrease the dilution to new investors by $0.82 per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us. If the options granted to certain of our executive officers under their respective employment agreements are exercised in full, the investors in this offering will experience further dilution. Please read "Dilution."

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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 of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our amended and restated certificate of incorporation and amended and restated bylaws and Delaware law make it more difficult to effect a change in control of our company, which could adversely affect the price of our common stock.

        The existence of some provisions in our amended and restated certificate of incorporation and amended and restated bylaws and the DGCL could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our amended and restated certificate of incorporation and amended and restated bylaws contain provisions that may make acquiring control of our company difficult, including:

    a classified Board of Directors, so that only approximately one-third of our directors are elected each year;

    provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;

    limitations on the ability of our stockholders to call a special meeting and act by written consent;

    the ability of our Board of Directors to adopt, amend or repeal our bylaws;

    the requirement that the affirmative vote of holders representing at least 662/3% of the voting power of all outstanding shares of capital stock (or a majority of the voting power of all outstanding shares of capital stock if Apollo beneficially owns at least 331/3% of the voting power of all such outstanding shares and votes in favor of the proposed action) be obtained to amend our amended and restated bylaws, to remove directors or to amend our certificate of incorporation; and

    the authorization given to our Board of Directors to issue and set the terms of preferred stock without the approval of our stockholders.

        These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for our common stock.

We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.

        We anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors. In addition, the terms of our debt agreements prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

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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 of 1933 (the "Securities Act") and Section 21E of the Securities and Exchange Act of 1934 (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," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "plan," "potential," "project," "forecast" and 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;

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    plans and objectives of management or our sponsors; and

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

        All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved when anticipated or at all. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this prospectus. These factors include, but are not limited to risks related to:

    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 credit agreement;

    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;

    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.

        These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

        There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation, and estimates may justify revisions based on the results of drilling, testing and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered.

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USE OF PROCEEDS

        We expect the net proceeds from this offering to be approximately $278.5 million, assuming an initial public offering price of $19.00 per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated underwriting discounts and commissions and estimated offering expenses of approximately $21.5 million, in the aggregate. Each $1.00 decrease in the public offering price would decrease our net proceeds by approximately $14.9 million.

        We intend to use the net proceeds of this offering, after deducting estimated underwriting discounts and comissions and estimated offering expenses, to purchase New Holdings Units from Athlon Holdings LP. The table below sets forth the anticipated use by Athlon Holdings LP of the net proceeds received by it as a result of our purchase of the New Holdings Units:

 
  Net Proceeds   Percentage of
Net Proceeds
 
 
  (in thousands)
   
 

Reduce outstanding indebtedness under our credit agreement

  $ 72,000     26 %

Provide additional liquidity for use in our drilling program

    206,500     74 %
           

Total

  $ 278,500     100 %
           

        Remaining net proceeds, if any, will be used for working capital and general corporate purposes, including potential acquisitions.

        As of July 22, 2013, we had $72 million of outstanding borrowings under our credit agreement. Our credit agreement matures on March 19, 2018 and bears interest at a variable rate, which was approximately 1.7% as of July 22, 2013. The borrowings to be repaid were incurred primarily to fund our acquisitions and development program. Amounts repaid under our credit agreement may be reborrowed at any time.

        We will not receive any proceeds from sales by the Apollo Funds, including pursuant to the underwriters' option to purchase additional shares of common stock.

        Affiliates of certain of the underwriters are lenders under our credit agreement and, accordingly, will receive a portion of the net proceeds from this offering. Please read "Underwriting (Conflicts of Interest)."


DIVIDEND POLICY

        We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our debt agreements restrict our ability to pay cash dividends to holders of our common stock.

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CAPITALIZATION

        The following table sets forth the cash and capitalization as of March 31, 2013 of:

    Athlon Holdings LP; and

    Athlon Energy Inc. on a pro forma as adjusted basis to give effect to (1) the reorganization transactions described under "Corporate Reorganization," (2) the offering by Athlon Holdings LP of $500 million of 73/8% senior notes due 2021 in April 2013, and the application of the net proceeds thereof, and (3) the sale of shares of our common stock in this offering at an assumed initial public offering price of $19.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus), our receipt of an estimated $278.5 million of net proceeds from this offering after deducting estimated underwriting discounts and commissions and estimated offering expenses and the use of those net proceeds as described under the caption "Use of Proceeds."

        You should read the following table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

 
  As of March 31, 2013  
 
  Athlon
Holdings LP1
Actual
  Athlon Energy Inc.
Pro Forma As
Adjusted1,2
 
 
  (in thousands)
 

Cash and cash equivalents

  $ 3,379   $ 275,103  
           

Debt:

             

Credit agreement3

  $ 291,426   $  

Former second lien term loan agreement4

    125,000      

73/8% senior notes due 2021

        500,000  
           

Total debt

    416,426     500,000  
           

Partners' equity

   
433,330
   
 
           

Stockholders' equity:

             

Preferred stock, $0.01 per share; 50,000,000 shares authorized, no shares issued and outstanding (pro forma as adjusted)

         

Common stock, $0.01 par value; 500,000,000 shares authorized (pro forma as adjusted); 82,122,646 shares issued and outstanding (pro forma as adjusted)

        821  

Additional paid-in capital

        625,371  

Accumulated deficit5

        (22,773 )
           

Total stockholders' equity

        603,419  

Noncontrolling interest

        9,429  
           

Total equity

    433,330     612,848  
           

Total capitalization

  $ 849,756   $ 1,112,848  
           

1
Athlon Energy Inc. was incorporated on April 1, 2013 in Delaware as a holding company and will not conduct any material business operations prior to the completion of this offering. The data in this table has been derived from the historical consolidated financial statements and other financial information included in this prospectus which pertain to the assets, liabilities, revenues and expenses of Athlon Holdings LP, our accounting predecessor.

2
Each $1.00 decrease in the public offering price would decrease our net proceeds from this offering by approximately $14.9 million.

3
We used a portion of the net proceeds from the senior notes offering to repay approximately $288.3 million of outstanding borrowings under our credit agreement. As of July 22, 2013, we had $72 million of outstanding borrowings under our credit agreement.

4
We used a portion of the net proceeds from the senior notes offering to repay in full and terminate our former second lien term loan agreement.

5
Upon completion of our corporate reorganization, we will recognize deferred tax liabilities and assets for temporary differences between the historical cost basis and tax basis of our assets and liabilities. Based on estimates of those temporary differences as of March 31, 2013, a net deferred tax liability of approximately $19.0 million will be recognized with a corresponding charge to earnings.

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DILUTION

        Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value (tangible assets less total liabilities) as of March 31, 2013, after giving pro forma effect to the transactions described under "Corporate Reorganization," and our senior notes offering, was approximately $336.5 million, or $5.07 per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma net tangible book value by our shares of common stock that will be outstanding immediately prior to the closing of this offering, including giving effect to the reorganization transactions described under "Corporate Reorganization" and our senior notes offering. Assuming an initial public offering price of $19.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of March 31, 2013 would have been approximately $612.8 million, or $7.46 per share. This represents an immediate increase in the net tangible book value of $2.39 per share to our existing stockholders and an immediate dilution to new investors purchasing shares in this offering of $11.54 per share, resulting from the difference between the offering price and the pro forma as adjusted net tangible book value after this offering. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

Assumed initial public offering price per share

        $ 19.00  

Pro forma net tangible book value per share as of March 31, 2013 (prior to this offering)

  $ 5.07        

Increase per share attributable to new investors in the offering

  $ 2.39        
             

As adjusted pro forma net tangible book value per share (after this offering)

          7.46  
             

Dilution in pro forma net tangible book value per share to new investors in this offering1

        $ 11.54  
             

1
If the initial public offering price were to decrease by $1.00 per share, then dilution in pro forma net tangible book value per share to new investors in this offering would equal $10.72.

        The following table sets forth, as of March 31, 2013, the number of shares of common stock held by our existing stockholders immediately prior to the closing of this offering, and by the new investors at the assumed initial public offering price of $19.00 per share (which is the midpoint of the price range set forth on the cover page of this prospectus), together with the total consideration paid and average price per share paid by each of these groups, before deducting estimated underwriting discounts and commissions and estimated offering expenses:

 
  Shares Purchased   Total Consideration    
 
 
  Average Price
Per Share
 
 
  Number   Percent   Amount   Percent  
 
   
   
  (in millions)
   
   
 

Existing stockholders

    66,333,172     80.8 % $ 361.9     54.7 % $ 5.46  

New investors

    15,789,474     19.2 %   300.0     45.3 %   19.00  
                         

Total

    82,122,646     100.0 % $ 661.9     100.0 %   8.06  
                         

        The data in the table excludes 8,400,000 shares of common stock initially reserved for issuance under the Athlon Energy Inc. 2013 Incentive Award Plan (which amount may be increased each year in accordance with the terms of the plan).

        If the underwriters' option to purchase additional shares of common stock from the Apollo Funds is exercised in full, the number of shares held by new investors will be increased to 18,157,895, or approximately 22.1% of our outstanding shares of common stock.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

        The following selected consolidated balance sheets data, statements of operations data and statements of cash flows data as of and for the years ended December 31, 2012 and 2011 are derived from, and qualified by reference to, the audited consolidated financial statements of Athlon Holdings LP, our accounting predecessor, included elsewhere in this prospectus and should be read in conjunction with those financial statements and notes thereto as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following selected consolidated balance sheet data as of March 31, 2013 and the consolidated statements of operations data and statements of cash flow data for the three months ended March 31, 2013 and 2012 are derived from, and qualified by reference to, the unaudited consolidated financial statements of Athlon Holdings LP, our accounting predecessor, included elsewhere in this prospectus and should be read in conjunction with those financial statements and notes thereto as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations." The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

 
  Three months ended
March 31,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (unaudited)
   
   
 
 
  (in thousands)
 

Consolidated Statements of Operations Data:

                         

Revenues:

                         

Oil

  $ 45,659   $ 27,433   $ 128,081   $ 51,193  

Natural gas

    3,367     1,448     8,415     3,521  

NGLs

    5,720     4,351     20,615     10,967  
                   

Total revenues

    54,746     33,232     157,111     65,681  
                   

Expenses:

                         

Production:

                         

Lease operating

    7,237     4,699     25,503     13,328  

Production, severance and ad valorem taxes          

    3,694     2,350     10,438     4,727  

Depletion, depreciation and amortization

    18,053     9,614     54,456     19,747  

General and administrative

    3,282     2,597     9,678     7,724  

Acquisition costs

    57         876     9,519  

Derivative fair value loss (gain)

    6,849     22,711     (9,293 )   7,959  

Other operating

    194     130     562     404  
                   

Total expenses

    39,366     42,101     92,220     63,408  
                   

Operating income (loss)

    15,380     (8,869 )   64,891     2,273  

Interest expense

    4,474     1,495     9,949     2,932  
                   

Income (loss) before income taxes

    10,906     (10,364 )   54,942     (659 )

Income tax provision (benefit)

    27     (364 )   1,928     470  
                   

Net income (loss)

  $ 10,879   $ (10,000 ) $ 53,014   $ (1,129 )
                   

Consolidated Statements of Cash Flows Data:

                         

Cash provided by (used in):

                         

Operating activities

  $ 30,397   $ 20,723   $ 95,302   $ 18,872  

Investing activities

    (90,560 )   (58,498 )   (347,259 )   (465,475 )

Financing activities

    54,671     12,982     228,798     471,627  

Consolidated Balance Sheets Data (at period end):

                         

Cash and cash equivalents

  $ 3,379         $ 8,871   $ 32,020  

Total assets

    916,535           852,298     561,823  

Total debt

    416,426           362,000     170,000  

Partners' equity

    433,330           420,877     327,452  

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

        The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Actual results could differ materially from those discussed in these forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information unless required to do so under federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" appearing elsewhere in this prospectus.

Overview

        We are an independent exploration and production company focused on the acquisition, development and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin. The Permian Basin spans portions of Texas and New Mexico and consists of three primary sub-basins: the Delaware Basin, the Central Basin Platform and the Midland Basin. All of our properties are located in the Midland Basin. Our drilling activity is currently focused on the low-risk vertical development of stacked pay zones, including the Spraberry, Wolfcamp, Cline, Strawn, Atoka and Mississippian formations, which we refer to collectively as the Wolfberry play. We are a returns-focused organization and have targeted the Wolfberry play in the Midland Basin because of its favorable operating environment, consistent reservoir quality across multiple target horizons, long-lived reserve characteristics and high drilling success rates.

        We were founded in August 2010 by a group of executives from Encore Acquisition Company following its acquisition by Denbury Resources, Inc. With an average of approximately 20 years of industry experience and over 10 years of history working together, our founding management has a proven track record of working as a team to acquire, develop and exploit oil and natural gas reserves in the Permian Basin as well as other resource plays in North America.

        Our acreage position was 124,925 gross (98,348 net) acres at May 31, 2013, which we group into three primary areas based on geographic location within the Midland Basin: Howard, Midland & Other and Glasscock. From the time we began operations in January 2011 through May 31, 2013, we have operated up to eight vertical drilling rigs simultaneously and have drilled 230 gross vertical Wolfberry wells with a 99% success rate across all three areas. This activity has allowed us to identify and de-risk our multi-year inventory of 4,902 gross (3,857 net) vertical drilling locations, while also identifying 1,079 gross (931 net) horizontal drilling locations in specific areas based on the geophysical and technical data as of May 31, 2013. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify additional horizontal drilling locations.

        As of December 31, 2012, we had 86 MMBOE of proved reserves. In addition, we have grown our production to 11,957 BOE/D for June 2013. As of December 31, 2012, our estimated proved reserves were approximately 58% oil, 22% NGLs and 20% natural gas and approximately 30% were proved developed reserves. Our PUDs include 597 gross (560 net) potential vertical drilling locations.

Our Acquisition History

        A significant portion of our historical growth has been achieved through acquisitions. Since our inception in August 2010, we have completed two significant acquisitions and seven bolt-on acquisitions. At the time of each acquisition, based on internal engineering estimates, these properties collectively contributed approximately 3,600 BOE/D of production and approximately 43 MMBOE of proved reserves.

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        On January 6, 2011, we acquired certain oil and natural gas properties and related assets, consisting of 19,210 gross (18,833 net) acres in the Permian Basin in West Texas, from SandRidge Exploration and Production, LLC ("SandRidge," and when discussing the transaction, the "SandRidge acquisition") for $156.0 million in cash, which was financed through borrowings under our credit agreement and capital contributions from partners. The SandRidge properties included approximately 1,600 BOE/D of production and approximately 19.1 MMBOE of proved reserves at the time of acquisition based on internal reserve reports.

        On October 3, 2011, we acquired certain oil and natural gas properties and related assets, consisting of 41,044 gross (34,400 net) acres in the Permian Basin in West Texas, from Element Petroleum, LP ("Element," and when discussing the transaction, the "Element acquisition") for $253.2 million in cash, which was financed through borrowings under our credit agreement and capital contributions from partners. The Element properties included approximately 1,400 BOE/D of production and approximately 16.4 MMBOE of proved reserves at the time of acquisition based on internal reserve reports.

Factors That Significantly Affect Our Financial Condition and Results of Operations

        Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators and geopolitical events such as wars or natural disasters. Sustained periods of low prices for oil, natural gas or NGLs could materially and adversely affect our financial condition, our results of operations, the quantities of oil and natural gas that we can economically produce and our ability to access capital.

        We use commodity derivative instruments, such as swaps, puts and collars to manage and reduce price volatility and other market risks associated with our oil production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions. We elected not to designate our current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings. Please read "—Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of our commodity derivative contracts.

        The prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing, Oklahoma transport hub and the Gulf Coast refineries. Periodically, logistical and infrastructure constraints at the Cushing, Oklahoma transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lower prices for Midland WTI. These lower prices have adversely affected the prices we realize on oil sales and increased our differential to NYMEX WTI. However, several projects have recently been implemented and several more are underway to ease these transportation difficulties which we believe could reduce our differentials to NYMEX in the future. We have also entered into Midland-Cushing differential swaps for 2013 to mitigate the adverse effects of any further widening of the Midland-Cushing WTI differential (the difference between Midland WTI and Cushing WTI).

        Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more

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reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

        As with our historical acquisitions, any future acquisitions could have a substantial impact on our financial condition and results of operations. In addition, funding future acquisitions may require us to incur additional indebtedness or issue additional equity.

        The volumes of oil and natural gas that we produce are driven by several factors, including:

    success in drilling wells, including exploratory wells, and the recompletion of existing wells;

    the amount of capital we invest in the leasing and development of our oil and natural gas properties;

    facility or equipment availability and unexpected downtime;

    delays imposed by or resulting from compliance with regulatory requirements; and

    the rate at which production volumes on our wells naturally decline.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

        Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

        Corporate Reorganization.    The historical consolidated financial statements included in this prospectus are based on the financial statements of Athlon Holdings LP, our accounting predecessor, prior to the reorganization transactions as described under "Corporate Reorganization." As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the reorganization transactions had been completed at the beginning of the periods presented or what our future results of operations are likely to be.

        Public Company Expenses.    Upon completion of this offering, we expect to incur direct, incremental general and administrative ("G&A") expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. We estimate these direct, incremental G&A expenses initially to total approximately $2.0 million per year. These direct, incremental G&A expenses are not included in our historical results of operations.

        Income Taxes.    Athlon Holdings LP, our accounting predecessor, is a limited partnership not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to Athlon Holdings LP's partners. However, we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings.

        Increased Drilling Activity.    We began operations in January 2011 and gradually added operated vertical drilling rigs. We currently operate seven vertical drilling rigs on our properties, and we have operated between five and eight drilling rigs since October 2011. Our 2013 development capital budget is approximately $317 million, including $15 million for infrastructure, leasing and capitalized workovers, and we expect to drill 162 gross (150 net) vertical Wolfberry wells. We also plan to invest

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$33 million of development capital to drill 4 gross (4 net) horizontal Wolfcamp wells. We expect to take delivery of our first horizontal rig in the third quarter of 2013 and our second horizontal rig in the second quarter of 2014. In 2014, we intend to expand to an eight-rig vertical drilling program. In addition, we intend to implement a horizontal drilling program in the second half of 2013 which we expect will significantly increase our capital expenditures in future periods. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results in each particular year.

        Element Acquisition.    On October 3, 2011, we acquired certain oil and natural gas properties and related assets, consisting of 41,044 gross (34,400 net) acres in the Element acquisition for $253.2 million in cash, which was financed through borrowings under our credit agreement and capital contributions from partners. Only three months of production from the Element properties is included in our results of operations for 2011.

        Financing Arrangements.    Through March 31, 2013, we had incurred $416.4 million of indebtedness, including $291.4 million under our credit agreement and $125 million under a second lien term loan agreement, which we refer to as our former second lien term loan. In April 2013, we issued $500 million in aggregate principal amount of 73/8% senior notes due 2021. We used the proceeds of our senior notes offering to repay a portion of the amounts outstanding under our credit agreement, to repay in full and terminate our former second lien term loan, to make a $75 million distribution to Class A limited partners of Athlon Holdings LP and for general corporate purposes. Our senior notes bear interest at a rate significantly higher than the rates under our credit agreement which will result in higher interest expense in future periods as compared to our historical interest expense. In the future, we may incur additional indebtedness to fund our acquisition and development activities. Please read "—Capital Commitments, Capital Resources, and Liquidity—Liquidity" for additional discussion of our financing arrangements.

Sources of Our Revenues

        Our revenues are derived from the sale of oil, natural gas and NGLs within the continental United States and do not include the effects of derivatives. For 2012, oil and NGLs represented approximately 80% of our total production volumes. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

        NYMEX WTI and Henry Hub prompt month contract prices are widely-used benchmarks in the pricing of oil and natural gas. The following table provides the high and low prices for NYMEX WTI and Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated:

 
  Three months ended
March 31,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  

Oil

                         

NYMEX WTI High

  $ 97.94   $ 109.77   $ 109.77   $ 113.93  

NYMEX WTI Low

    90.12     96.36     77.69     75.67  

Differential to Average NYMEX WTI

    (10.11 )   (3.66 )   (6.29 )   (3.03 )

Natural Gas

                         

NYMEX Henry Hub High

    4.07     3.10     3.90     4.85  

NYMEX Henry Hub Low

    3.11     2.13     1.91     2.99  

Differential to Average NYMEX Henry Hub

    (0.07 )   (0.03 )   (0.13 )   (0.54 )

        We normally sell production to a relatively small number of customers. In 2012, three purchasers individually accounted for more than 10% of our revenues: Pecos Gathering & Marketing (43%);

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Occidental Petroleum Corporation (29%); and DCP Midstream (12%). If any significant customer decided to stop purchasing oil and natural gas from us, our revenues could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our significant customers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Principal Components of Our Cost Structure

        Lease Operating Expense.    LOE includes the daily costs incurred to bring crude oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs include field personnel compensation, utilities, maintenance and workover expenses related to our oil and natural gas properties.

        Production, Severance and Ad Valorem Taxes.    Production and severance taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production and severance taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties and are assessed annually.

        Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization ("DD&A") is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. We use the full cost method of accounting for oil and natural gas activities. Please read "—Critical Accounting Policies and Estimates—Method of Accounting for Oil and Natural Gas Properties" for further discussion.

        General and Administrative Expense.    G&A expense consists of company overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees and legal compliance costs. Upon completion of this offering, G&A expense will also include public company expenses as described above under "—Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations—Public Company Expenses."

        Interest Expense.    We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our credit agreement. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees are included in interest expense. Interest expense is net of capitalized interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest expense will also include interest incurred under our senior notes beginning April 2013 as described above under "—Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations—Financing Arrangements."

        Derivative Fair Value Loss (Gain).    We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in

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our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

How We Evaluate Our Operations

        In evaluating our financial results, we focus on the mix of our revenues from oil, natural gas and NGLs, the average realized price from sales of our production, our production margins and our net income. Below are highlights of our financial and operating results for the first quarter of 2013:

    Our oil, natural gas and NGLs revenues increased 65% to $54.7 million in the first quarter of 2013 as compared to $33.2 million in the first quarter of 2012.

    Our average daily production volumes increased 94% to 9,959 BOE/D in the first quarter of 2013 as compared to 5,140 BOE/D in the first quarter of 2012. Oil and NGLs represented approximately 81% of our total production volumes in the first quarter of 2013.

    Our average realized oil price decreased 15% to $84.23 per Bbl in the first quarter of 2013 as compared to $99.29 per Bbl in the first quarter of 2012. Our average realized natural gas price increased 21% to $3.27 per Mcf in the first quarter of 2013 as compared to $2.71 per Mcf in the first quarter of 2012. Our average realized NGL price decreased 26% to $31.34 per Bbl in the first quarter of 2013 as compared to $42.48 per Bbl in the first quarter of 2012.

    Our production margin increased 67% to $43.8 million in the first quarter of 2013 as compared to $26.2 million in the first quarter of 2012. Total wellhead revenues per BOE decreased by 14% and total production expenses per BOE decreased by 19%. On a per BOE basis, our production margin decreased 13% to $48.84 per BOE in the first quarter of 2013 as compared to $55.92 per BOE for the first quarter of 2012.

    Our net income was $10.9 million as compared to a net loss of $10.0 million for the first quarter of 2012.

    We invested $80.9 million in oil and natural gas activities, of which $71.8 million was invested in development and exploration activities, yielding 35 gross (34 net) productive wells, and $9.1 million was invested in acquisitions.

        We also evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with the technical capabilities of our management team can generate attractive rates of return as we develop our extensive resource base. Additionally, by focusing on concentrated acreage positions, we can build and own centralized production infrastructure, including saltwater disposal facilities, which enable us to reduce reliance on outside service companies, minimize costs and increase our returns.

        We measure the expected return of our wells based on EUR and the related costs of acquisition, development and production. Based on estimates prepared by our independent reserve engineers, as of December 31, 2012, the wells we expect to drill in 2013 through the Atoka formation in Howard, Midland & Other and Glasscock areas have an average EUR of 141 MBOE (87 MBbls of oil, 150 MMcf of natural gas and 30 MBbls of NGLs), 208 MBOE (95 MBbls of oil, 318 MMcf of natural gas and 60 MBbls of NGLs) and 118 MBOE (73 MBbls of oil, 141 MMcf of natural gas and 22 MBbls of NGLs), respectively. Our average drilling and completion cost per vertical well drilled in the Howard, Midland & Other and Glasscock areas in the first quarter of 2013 was $1.8 million, $2.15 million and $1.8 million, respectively, with average 30-day initial production rates of approximately 130 BOE/D, 190 BOE/D and 100 BOE/D, respectively. Assuming a benchmark crude oil price of $94.71 per Bbl and natural gas price of $2.75 per Mcf, the PUD wells we expect to drill in 2013 in the Howard, Midland & Other and Glasscock areas are targeted to produce an average rate of return of 34%, 43% and 21%, respectively.

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Results of Operations

    Comparison of Quarter Ended March 31, 2013 to Quarter Ended March 31, 2012

        Revenues.    The following table provides the components of our revenues for the periods indicated, as well as each period's respective production volumes and average prices:

 
  Three months ended
March 31,
  Increase /
(Decrease)
 
 
  2013   2012   $   %  

Revenues (in thousands):

                         

Oil

  $ 45,659   $ 27,433   $ 18,226     66 %

Natural gas

    3,367     1,448     1,919     133 %

NGLs

    5,720     4,351     1,369     31 %
                     

Total revenues

  $ 54,746   $ 33,232   $ 21,514     65 %
                     

Average realized prices:

                         

Oil ($/Bbl) (excluding impact of cash settled derivatives)

  $ 84.23   $ 99.29   $ (15.06 )   -15 %

Oil ($/Bbl) (after impact of cash settled derivatives)

  $ 83.65   $ 89.53   $ (5.88 )   -7 %

Natural gas ($/Mcf)

  $ 3.27   $ 2.71   $ 0.56     21 %

NGLs ($/Bbl)

  $ 31.34   $ 42.48   $ (11.14 )   -26 %

Combined ($/BOE) (excluding impact of cash settled derivatives)

  $ 61.08   $ 71.05   $ (9.97 )   -14 %

Combined ($/BOE) (after impact of cash settled derivatives)

  $ 60.73   $ 65.28   $ (4.55 )   -7 %

Total production volumes:

                         

Oil (MBbls)

    542     276     266     96 %

Natural gas (MMcf)

    1,030     534     496     93 %

NGLs (MBbls)

    183     102     81     79 %

Combined (MBOE)

    896     468     428     91 %

Average daily production volumes:

                         

Oil (Bbls/D)

    6,023     3,036     2,987     98 %

Natural gas (Mcf/D)

    11,446     5,871     5,575     95 %

NGLs (Bbls/D)

    2,028     1,125     903     80 %

Combined (BOE/D)

    9,959     5,140     4,819     94 %

        The following table shows the relationship between our average oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 
  Three months ended
March 31,
 
 
  2013   2012  

Average realized oil price ($/Bbl)

  $ 84.23   $ 99.29  

Average NYMEX ($/Bbl)

  $ 94.34   $ 102.95  

Differential to NYMEX

  $ (10.11 ) $ (3.66 )

Average realized oil price to NYMEX percentage

    89 %   96 %

Average realized natural gas price ($/Mcf)

 
$

3.27
 
$

2.71
 

Average NYMEX ($/Mcf)

  $ 3.34   $ 2.74  

Differential to NYMEX

  $ (0.07 ) $ (0.03 )

Average realized natural gas price to NYMEX percentage

    98 %   99 %

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        Our average realized oil price as a percentage of the average NYMEX price was 89% for the first quarter of 2013 as compared to 96% for the first quarter of 2012. All of our oil contracts include the Midland-Cushing differential, which widened to a negative $7.78 per Bbl in the first quarter of 2013 as compared to a negative $1.51 per Bbl in the first quarter of 2012 primarily due to difficulty transporting oil from the Permian Basin to the Gulf Coast refineries due to lack of logistics and infrastructure. However, several projects have recently been implemented and several more are underway to ease these transportation difficulties which we believe will reduce our differentials to NYMEX in the future. We began to see a tightening of our oil differentials in March and have continued to see improvement into the second quarter of 2013 where the differential has decreased to a negative $0.18 per Bbl average for May 2013. Our average realized natural gas price as a percentage of the average NYMEX price remained stable at 98% for the first quarter of 2013 as compared to 99% for the first quarter of 2012.

        Oil revenues increased 66% from $27.4 million in the first quarter of 2012 to $45.7 million in the first quarter of 2013 as a result of an increase in our oil production volumes of 266 MBbls, partially offset by a $15.06 per Bbl decrease in our average realized oil price. Our higher oil production increased oil revenues by $26.4 million and was primarily the result of our development program in the Permian Basin. Our lower average realized oil price decreased oil revenues by $8.2 million and was primarily due to a lower average NYMEX price, which decreased from $102.95 per Bbl in the first quarter of 2012 to $94.34 per Bbl in the first quarter of 2013, and the widening of our oil differentials as previously discussed.

        Natural gas revenues increased 133% from $1.4 million in the first quarter of 2012 to $3.4 million in the first quarter of 2013 as a result of an increase in our natural gas production volumes of 496 MMcf and a $0.56 per Mcf increase in our average realized natural gas price. Our higher natural gas production increased natural gas revenues by $1.4 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring a portion of our natural gas production as either (1) our well is not yet tied into the third-party gathering system, (2) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported or (3) our production is prorated due to high demand on the third-party gathering system. During the first quarter of 2013, we flared an average of approximately 2.0 MMcf/D, or 331 BOE/D, of natural gas, which included both residue gas and NGL production. We expect to continue flaring approximately 3.0 MMcf/D to 4.0 MMcf/D until further improvements can be made to various gathering systems near our wells, which is scheduled to occur in mid-2013. Our higher average realized natural gas price increased natural gas revenues by $0.6 million and was primarily due to a higher average NYMEX price, which increased from $2.74 per Mcf in the first quarter of 2012 to $3.34 per Mcf in the first quarter of 2013.

        NGL revenues increased 31% from $4.4 million in the first quarter of 2012 to $5.7 million in the first quarter of 2013 as a result of an increase in our NGL production volumes of 81 MBbls, partially offset by an $11.14 per Bbl decrease in our average realized NGL price. Our higher NGL production increased NGL revenues by $3.4 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring a portion of our natural gas as described above. Our lower average realized NGL price decreased NGL revenues by $2.0 million and was primarily due to increased supplies of NGLs from NGL-rich shales in the Permian Basin and other basins including the Eagle Ford and the Williston.

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        Expenses.    The following table summarizes our expenses for the periods indicated:

 
  Three months ended
March 31,
  Increase /
(Decrease)
 
 
  2013   2012   $   %  

Expenses (in thousands):

                         

Production:

                         

Lease operating

  $ 7,237   $ 4,699   $ 2,538     54 %

Production, severance and ad valorem taxes

    3,694     2,350     1,344     57 %

Processing, gathering and overhead

    45     24     21     88 %
                     

Total production expenses

    10,976     7,073     3,903     55 %

Other:

                         

Depletion, depreciation and amortization

    18,053     9,614     8,439     88 %

General and administrative

    3,339     2,597     742     29 %

Derivative fair value loss

    6,849     22,711     (15,862 )   -70 %

Accretion

    149     106     43     41 %
                     

Total operating

    39,366     42,101     (2,735 )   -6 %

Interest

    4,474     1,495     2,979     199 %

Income tax provision (benefit)

    27     (364 )   391     -107 %
                     

Total expenses

  $ 43,867   $ 43,232   $ 635     1 %
                     

Expenses (per BOE):

                         

Production:

                         

Lease operating

  $ 8.07   $ 10.05   $ (1.98 )   -20 %

Production, severance and ad valorem taxes

    4.12     5.03     (0.91 )   -18 %

Processing, gathering and overhead

    0.05     0.05         0 %
                     

Total production expenses

    12.24     15.13     (2.89 )   -19 %

Other:

                         

Depletion, depreciation and amortization

    20.14     20.55     (0.41 )   -2 %

General and administrative

    3.73     5.55     (1.82 )   -33 %

Derivative fair value loss

    7.64     48.55     (40.91 )   -84 %

Accretion

    0.17     0.23     (0.06 )   -26 %
                     

Total operating

    43.92     90.01     (46.09 )   -51 %

Interest

    4.99     3.20     1.79     56 %

Income tax provision (benefit)

    0.03     (0.78 )   0.81     -104 %
                     

Total expenses

  $ 48.94   $ 92.43   $ (43.49 )   -47 %
                     

        Production expenses.    Production expenses attributable to LOE increased 54% from $4.7 million in the first quarter of 2012 to $7.2 million in the first quarter of 2013 as a result of an increase in production volumes from wells drilled, which contributed $4.3 million of additional LOE, partially offset by a $1.98 decrease in the average per BOE rate, which reduced LOE by $1.8 million. The decrease in our average LOE per BOE rate was attributable to wells we successfully drilled and completed in 2012 and the first quarter of 2013 where we are experiencing economies of scale from our drilling program and from savings achieved through 2012 infrastructure projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of water.

        Production expenses attributable to production, severance and ad valorem taxes increased 57% from $2.4 million in the first quarter of 2012 to $3.7 million in the first quarter of 2013 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts, resulting from increased production from our drilling activity. As a percentage of wellhead revenues, production,

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severance, and ad valorem taxes decreased to 6.7% in the first quarter of 2013 as compared to 7.1% in the first quarter of 2012 primarily due to (1) an increase in oil revenues as a percentage of our total revenues, which are taxed at a lower rate than natural gas and NGLs, and (2) an increase in the number of wells brought on production in the first quarter of 2013 as compared to the first quarter of 2012 as we continue to utilize more efficient drilling rigs and reduce our time from spud to rig release. Wells brought on production during the first quarter of 2013 contributed to our production, but will not have ad valorem taxes assessed until 2014.

        DD&A expense.    DD&A expense increased 88% from $9.6 million in the first quarter of 2012 to $18.1 million in the first quarter of 2013 primarily due to an increase in production volumes and an increase in our asset base subject to amortization as a result of our drilling activity in 2012 and the first quarter of 2013.

        G&A expense.    G&A expense increased 29% from $2.6 million in the first quarter of 2012 to $3.3 million in the first quarter of 2013 primarily due to higher payroll and payroll-related costs as we continued to add employees in order to manage our growing asset base.

        Derivative fair value loss.    During the first quarter of 2013, we recorded a $6.8 million derivative fair value loss as compared to a loss of $22.7 million in the first quarter of 2012. The change in our derivative fair value loss was a result of additional oil swaps and basis differential swaps entered into during the first quarter of 2013 and the decrease in the future commodity price outlook during the first quarter of 2013 as compared to the first quarter of 2012, which favorably impacted the fair values of our commodity derivative contracts.

        Interest expense.    Interest expense increased 199% from $1.5 million in the first quarter of 2012 to $4.5 million in the first quarter of 2013 primarily due to higher weighted-average outstanding borrowings under our credit agreement and the issuance of $125 million of debt under our former second lien term loan in September 2012. Our weighted-average outstanding borrowings under our credit agreement were $272.0 million for the first quarter of 2013 as compared to $169.4 million for the first quarter of 2012. Our weighted-average interest rate for total indebtedness was 4.6% for the first quarter of 2013 as compared to 3.5% for the first quarter of 2012. Our weighted-average outstanding borrowings increased in the first quarter of 2013 as compared to the first quarter of 2012 in order to fund our higher level of development and exploration activities during 2012 and the first quarter of 2013.

        The following table provides the components of our interest expense for the periods indicated:

 
  Three months
ended
March 31,
   
 
 
  Increase /
(Decrease)
 
 
  2013   2012  
 
  (in thousands)
 

Credit agreement

  $ 1,923   $ 1,359   $ 564  

Former second lien term loan agreement

    2,350         2,350  

Other

    243     136     107  

Less: interest capitalized

    (42 )       (42 )
               

Total

  $ 4,474   $ 1,495   $ 2,979  
               

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    Comparison of 2012 to 2011

        Revenues.    The following table provides the components of our revenues for the periods indicated, as well as each period's respective production volumes and average prices:

 
  Year ended December 31   Increase/(Decrease)  
 
  2012   2011   $   %  

Revenues (in thousands):

                         

Oil

  $ 128,081   $ 51,193   $ 76,888     150 %

Natural gas

    8,415     3,521     4,894     139 %

NGLs

    20,615     10,967     9,648     88 %
                     

Total revenues

  $ 157,111   $ 65,681   $ 91,430     139 %
                     

Average realized prices:

                         

Oil ($/Bbl) (excluding impact of cash settled derivatives)

  $ 87.90   $ 92.08   $ (4.18 )   -5 %

Oil ($/Bbl) (after impact of cash settled derivatives)

  $ 87.16   $ 87.16   $     0 %

Natural gas ($/Mcf)

  $ 2.66   $ 3.46   $ (0.80 )   -23 %

NGLs ($/Bbl)

  $ 34.65   $ 45.96   $ (11.31 )   -25 %

Combined ($/BOE) (excluding impact of cash settled derivatives)

  $ 60.91   $ 68.13   $ (7.22 )   -11 %

Combined ($/BOE) (after impact of cash settled derivatives)

  $ 60.50   $ 65.29   $ (4.79 )   -7 %

Total production volumes:

                         

Oil (MBbls)

    1,457     556     901     162 %

Natural gas (MMcf)

    3,163     1,017     2,146     211 %

NGLs (MBbls)

    595     239     356     149 %

Combined (MBOE)

    2,579     964     1,615     168 %

Average daily production volumes:

                         

Oil (Bbls/D)

    3,981     1,523     2,458     161 %

Natural gas (Mcf/D)

    8,641     2,786     5,855     210 %

NGLs (Bbls/D)

    1,625     654     971     148 %

Combined (BOE/D)

    7,047     2,641     4,406     167 %

        The following table shows the relationship between our average oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 
  Year ended December 31,  
 
  2012   2011  

Average realized oil price ($/Bbl)

  $ 87.90   $ 92.08  

Average NYMEX ($/Bbl)

    94.19     95.11  

Differential to NYMEX

    (6.29 )   (3.03 )

Average realized oil price to NYMEX percentage

    93 %   97 %

Average realized natural gas price ($/Mcf)

  $ 2.66   $ 3.46  

Average NYMEX ($/Mcf)

    2.79     4.00  

Differential to NYMEX

    (0.13 )   (0.54 )

Average realized natural gas price to NYMEX percentage

    95 %   87 %

        Our average realized oil price as a percentage of the average NYMEX price was 93% for 2012 as compared to 97% for 2011. All of our oil contracts include the Midland-Cushing differential, which widened in 2012 due to difficulty transporting oil production from the Permian Basin to the Gulf Coast refineries as a result of lack of logistics and infrastructure. However, several projects have recently been

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implemented and several more are underway to ease these transportation difficulties which we believe could reduce our differentials to NYMEX in the future. Our average realized natural gas price as a percentage of the average NYMEX price improved to 95% for 2012 as compared to 87% for 2011 as a result of a full year of production from the properties acquired from Element, which have a higher percentage of their natural gas contracts weighted to an index that trades closer to the average NYMEX price than the natural gas contracts related to the properties acquired from SandRidge.

        Oil revenues increased 150% from $51.2 million in 2011 to $128.1 million in 2012 as a result of an increase in our oil production volumes of 901 MBbls, partially offset by a $4.18 per Bbl decrease in our average realized oil price. Our higher oil production increased oil revenues by $83.0 million and was primarily the result of a full year of production from our Element acquisition in October 2011, as well as our development program in the Permian Basin. The properties initially acquired from Element contributed approximately 113 MBbls ($10.1 million in revenue) of additional oil production in 2012 as compared to 2011 while our development program contributed approximately 788 MBbls ($72.9 million in revenue) of additional oil production. Our lower average realized oil price decreased oil revenues by $6.1 million and was primarily due to a lower average NYMEX price, which decreased from $95.11 per Bbl in 2011 to $94.19 per Bbl in 2012, and the widening of our oil differentials as previously discussed.

        Natural gas revenues increased 139% from $3.5 million in 2011 to $8.4 million in 2012 as a result of an increase in our natural gas production volumes of 2,146 MMcf, partially offset by a $0.80 per Mcf decrease in our average realized natural gas price. Our higher natural gas production increased natural gas revenues by $7.4 million and was primarily the result of a full year of production from our Element acquisition in October 2011, as well as our development program in the Permian Basin. The properties initially acquired from Element contributed approximately 299 MMcf ($0.8 million in revenue) of additional natural gas production in 2012 as compared to 2011 while our development program contributed approximately 1,847 MMcf ($6.6 million in revenue) of additional natural gas production. Our lower average realized natural gas price decreased natural gas revenues by $2.5 million and was primarily due to a lower average NYMEX price, which decreased from $4.00 per Mcf in 2011 to $2.79 per Mcf in 2012, partially offset by the improvement in our natural gas differentials as previously discussed.

        NGL revenues increased 88% from $11.0 million in 2011 to $20.6 million in 2012 as a result of an increase in our NGL production volumes of 356 MBbls, partially offset by an $11.31 per Bbl decrease in our average realized NGL price. Our higher NGL production increased NGL revenues by $16.4 million and was primarily the result of a full year of production from our Element acquisition in October 2011, as well as our development program in the Permian Basin. The properties initially acquired from Element contributed approximately 50 MBbls ($1.5 million in revenue) of additional NGL production in 2012 as compared to 2011 while our development program contributed approximately 306 MBbls ($14.9 million in revenue) of additional NGL production. Our lower average realized NGL price decreased NGL revenues by $6.7 million and was primarily due to increased supplies of NGLs from NGL-rich shales in the Permian Basin and other basins including the Eagle Ford and the Williston.

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        Expenses.    The following table summarizes our expenses for the periods indicated:

 
  Year ended December 31,   Increase/(Decrease)  
 
  2012   2011   $   %  

Expenses (in thousands):

                         

Production:

                         

Lease operating

  $ 25,503   $ 13,328   $ 12,175     91 %

Production, severance and ad valorem taxes

    10,438     4,727     5,711     121 %

Processing, gathering and overhead

    84     60     24     40 %
                     

Total production expenses

    36,025     18,115     17,910     99 %

Other:

                         

Depletion, depreciation and amortization

    54,456     19,747     34,709     176 %

General and administrative

    9,678     7,724     1,954     25 %

Acquisition costs

    876     9,519     (8,643 )   -91 %

Derivative fair value loss (gain)

    (9,293 )   7,959     (17,252 )   -217 %

Accretion

    478     344     134     39 %
                     

Total operating expenses

    92,220     63,408     28,812     45 %

Interest

    9,949     2,932     7,017     239 %

Income tax provision

    1,928     470     1,458     310 %
                     

Total expenses

  $ 104,097   $ 66,810   $ 37,287     56 %
                     

Expenses (per BOE):

                         

Production:

                         

Lease operating

  $ 9.89   $ 13.82   $ (3.93 )   -28 %

Production, severance and ad valorem taxes

    4.05     4.90     (0.85 )   -17 %

Processing, gathering and overhead

    0.03     0.06     (0.03 )   -50 %
                     

Total production expenses

    13.97     18.78     (4.81 )   -26 %

Other:

                         

Depletion, depreciation and amortization

    21.11     20.48     0.63     3 %

General and administrative

    3.75     8.01     (4.26 )   -53 %

Acquisition costs

    0.34     9.87     (9.53 )   -97 %

Derivative fair value loss (gain)

    (3.60 )   8.26     (11.86 )   -144 %

Accretion

    0.19     0.36     (0.17 )   -47 %
                     

Total operating

    35.76     65.76     (30.00 )   -46 %

Interest

    3.86     3.04     0.82     27 %

Income tax provision

    0.75     0.49     0.26     53 %
                     

Total expenses

  $ 40.37   $ 69.29   $ (28.92 )   -42 %
                     

        Production expenses.    Production expenses attributable to LOE increased $12.2 million from $13.3 million in 2011 to $25.5 million in 2012 as a result of an increase in production volumes from drilled wells and a full year of LOE from our Element acquisition, which contributed $22.3 million of additional LOE, partially offset by a $3.93 decrease in the average per BOE rate, which reduced LOE by $10.1 million. The decrease in our average LOE per BOE rate was attributable to wells we successfully drilled and completed in 2012 where we are experiencing economies of scale from our drilling program and from savings achieved through 2012 infrastructure projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of water.

        Production expenses attributable to production, severance and ad valorem taxes increased $5.7 million from $4.7 million in 2011 to $10.4 million in 2012 primarily due to higher wellhead

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revenues, which exclude the effects of commodity derivative contracts, resulting from increased production from our acquisitions and drilling activity. As a percentage of wellhead revenues, production, severance and ad valorem taxes decreased to 6.6% in 2012 as compared to 7.2% in 2011 primarily due to an increase in oil revenues as a percentage of our total revenues, which are taxed at a lower rate than natural gas and NGLs, and because wells drilled in 2012 that contributed to our 2012 production will not have ad valorem taxes assessed until 2013.

        DD&A expense.    DD&A expense increased $34.7 million from $19.7 million in 2011 to $54.5 million in 2012 primarily due to a full year of production from the properties acquired in our Element acquisition and an increase in our asset base subject to amortization as a result of our 2012 drilling activity.

        G&A expense.    G&A expense increased $2.0 million from $7.7 million in 2011 to $9.7 million in 2012 primarily due to higher payroll and payroll-related costs as we added additional employees to manage our growing asset base.

        Acquisition costs.    Acquisition costs decreased $8.6 million from $9.5 million in 2011 to $0.9 million in 2012. We are party to a Transaction Fee Agreement, dated August 23, 2010, which requires us to pay a fee to Apollo equal to 2% of the total equity contributed to us, as defined in the agreement, in exchange for consulting and advisory services provided by Apollo. Upon the closing of the SandRidge acquisition in January 2011, we incurred a transaction fee payable to Apollo of $2.3 million. Upon the closing of the Element acquisition in October 2011, we incurred a transaction fee payable to Apollo of $4.3 million. In addition, we incurred other transaction costs associated with those significant acquisitions in 2011.

        Derivative fair value loss (gain).    During 2012, we recorded a $9.3 million derivative fair value gain as compared to an $8.0 million derivative fair value loss in 2011. The change in our derivative fair value loss (gain) was a result of additional oil swaps entered into during 2012 and the decrease in the future commodity price outlook during 2012, which favorably impacted the fair values of our commodity derivative contracts.

        Interest expense.    Interest expense increased $7.0 million from $2.9 million in 2011 to $9.9 million in 2012 primarily due to higher weighted-average outstanding borrowings under our credit agreement and the issuance of $125 million of debt under our former second lien term loan in September 2012. Our weighted-average outstanding borrowings under credit agreements were $196.5 million for 2012 as compared to $78.4 million for 2011. Our weighted-average interest rate for total indebtedness was 4.3% for 2012 as compared to 3.8% for 2011. Our weighted-average outstanding borrowings increased in 2012 in order to fund the closing of the Element acquisition in October 2011 and our higher level of development and exploration activities during 2012.

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        The following table provides the components of our interest expense for the periods indicated:

 
  Year ended December 31,    
 
 
  Increase/
(Decrease)
 
 
  2012   2011  
 
  (in thousands)
 

Credit agreements

  $ 5,932   $ 2,387   $ 3,545  

Former second lien term loan

    3,081         3,081  

Other

    1,155     545     610  

Less: interest capitalized

    (219 )       (219 )
               

Total

  $ 9,949   $ 2,932   $ 7,017  
               

Capital Commitments, Capital Resources, and Liquidity

    Capital commitments

        Our primary uses of cash are:

    Development and exploration of oil and natural gas properties;

    Acquisitions of oil and natural gas properties;

    Funding of working capital; and

    Contractual obligations.

        Development and exploration of oil and natural gas properties.    The following table summarizes our costs incurred related to development and exploration activities for the periods indicated:

 
  Three months ended
March 31,
  Year ended December 31,  
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Development

  $ 49,238   $ 24,370   $ 201,174   $ 71,403  

Exploration

    22,553     24,871     75,008     17,829  
                   

Total

  $ 71,791   $ 49,241   $ 276,182   $ 89,232  
                   

        Our development capital primarily relates to drilling development and infill wells, workovers of existing wells and field related facilities. Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals and geological and geophysical costs.

        Our development capital for the first quarter of 2013 yielded 19 gross (19 net) productive wells and no dry holes. Our exploration capital for the first quarter of 2013 yielded 16 gross (15 net) productive wells and no dry holes. The level of our development and exploration activities in the first quarter of 2013 were higher than in the first quarter of 2012 primarily due to our utilization of more efficient vertical drilling rigs that have significantly reduced the time from spud to rig release allowing us to drill more wells.

        Our development capital for 2012 yielded 102 gross (94 net) productive wells and two gross (two net) dry holes. Our exploration capital for 2012 yielded 29 gross (28 net) productive wells and no dry holes. The level of our development and exploration activities in 2012 were higher than in 2011 due to the increase in our operated drilling rigs from three to six upon the closing of the Element acquisition in October 2011.

        In 2013, we plan to invest approximately $317 million of development capital, including $15 million for infrastructure, leasing and capitalized workovers, and drill 162 gross (150 net) vertical Wolfberry

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wells. We also plan to invest $33 million of development capital to drill 4 gross (4 net) horizontal Wolfcamp wells. Our 2013 development capital consists of:

    $335 million of drilling and completion capital;

    $5 million for infrastructure and other non-drilling capital projects as well as workovers of existing wells; and

    $10 million for expanding our leasehold position.

        Acquisitions of oil and natural gas properties.    The following table summarizes our costs incurred related to oil and natural gas property acquisitions for the periods indicated:

 
  Year ended December 31,  
 
  2012   2011  
 
  (in thousands)
 

Acquisitions of proved properties

  $ 42,122   $ 287,400  

Acquisitions of unproved properties

    38,908     130,273  
           

Total

  $ 81,030   $ 417,673  
           

        We did not have any significant acquisitions during either the first quarter of 2013 or the first quarter of 2012.

        In the fourth quarter of 2012, we acquired certain oil and natural gas properties and related assets in the Permian Basin from three different sellers totaling for $74.9 million in cash.

        In January 2011, we acquired certain oil and natural gas properties and related assets in the Permian Basin from SandRidge for $156.0 million in cash. In October 2011, we acquired certain oil and natural gas properties and related assets in the Permian Basin from Element for $253.2 million in cash.

        Funding of working capital.    As of March 31, 2013 and December 31, 2012, our working capital deficit (defined as total current assets less total current liabilities) was $20.0 million and $22.2 million, respectively. Through 2013, we expect to continue to have working capital deficits primarily due to amounts accrued related to our extensive development activities. We expect our cash flows from operating activities and availability under our credit agreement after application of the estimated net proceeds from this offering, as described under "Use of Proceeds," will be sufficient to fund our working capital needs, capital expenditures and other obligations for at least the next 12 months. We expect that our production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

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        Contractual obligations.    The following table provides our contractual obligations and commitments as of December 31, 2012:

 
  Payments Due by Period  
Contractual Obligations and Commitments
  Total   2013   2014 - 2015   2016 - 2017   Thereafter  
 
  (in thousands)
 

Credit agreement1

  $ 265,370   $ 6,468   $ 12,936   $ 245,966   $  

Former second lien term loan1

    170,848     9,375     18,750     142,723      

Development commitments2

    39,483     39,483              

Operating leases and commitments3

    1,787     471     938     378      

Asset retirement obligations4

    29,405                 29,405  
                       

Total

  $ 506,893   $ 55,797   $ 32,624   $ 389,067   $ 29,405  
                       

1
Includes principal and projected interest payments. Please read "—Liquidity" for additional information regarding our long-term debt.

2
Represents authorized purchases for work in process related to our drilling activities.

3
Represents operating leases that have non-cancelable lease terms in excess of one year.

4
Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors.

        The above table does not reflect our April 2013 senior notes offering and the application of the net proceeds therefrom.

        As of December 31, 2012, the fair value of our commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk, was a net asset of $4.0 million. Please read "—Quantitative and Qualitative Disclosures about Market Risk" for additional information regarding our commodity derivative contracts.

        Off-balance sheet arrangements.    We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources. We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, an effect on our financial condition or results of operations.

    Capital resources

        The following table summarizes our cash flows for the periods indicated:

 
  Three months ended
March 31,
  Year ended December 31,  
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Net cash provided by operating activities

  $ 30,397   $ 20,723   $ 95,302   $ 18,872  

Net cash used in investing activities

    (90,560 )   (58,498 )   (347,259 )   (465,475 )

Net cash provided by financing activities

    54,671     12,982     228,798     471,627  
                   

Net increase (decrease) in cash

  $ (5,492 ) $ (24,793 ) $ (23,159 ) $ 25,024  
                   

        Cash flows from operating activities.    Cash provided by operating activities increased $9.7 million from $20.7 million in the first quarter of 2012 to $30.4 million in the first quarter of 2013, primarily due to an increase in our production margin due to a 91% increase in production as a result of wells

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drilled, partially offset by increased expenses as a result of having more producing wells in the first quarter of 2013 as compared to the first quarter of 2012.

        Cash provided by operating activities increased $76.4 million from $18.9 million in 2011 to $95.3 million in 2012, primarily due to an increase in our production margin as a result of a full year of production from our Element acquisition and wells drilled, partially offset by increased expenses as a result of our increased drilling activities in 2012 as compared to 2011.

        Cash flows used in investing activities.    Cash used in investing activities increased $32.1 million from $58.5 million in the first quarter of 2012 to $90.6 million in the first quarter of 2013, primarily due to a $24.5 million increase in amounts paid to develop oil and natural gas properties as we utilized more efficient vertical drilling rigs that have significantly reduced the time from spud to rig release allowing us to drill and complete more wells over the same time period.

        Cash used in investing activities decreased $118.2 million from $465.5 million in 2011 to $347.3 million in 2012, primarily due to a $334.2 million decrease in amounts paid to acquire oil and natural gas properties, which in 2011 included our SandRidge and Element acquisitions, partially offset by a $208.8 million increase in amounts paid to develop oil and natural gas properties as we utilized at least six rigs for the majority of 2012. In January 2011, we terminated certain oil puts that were in place at December 31, 2010 and received net proceeds of $7.6 million, which are included in cash used in investing activities for 2011.

        Cash flows from financing activities.    Our cash flows from financing activities consist primarily of net proceeds from and payments on long-term debt and contributions from partners. We periodically draw on our credit agreement and seek funding from partners to fund acquisitions and other capital commitments.

        During the first quarter of 2013, we received net cash of $54.7 million from financing activities, including net borrowings of $54.4 million under our credit agreement, which were used primarily to finance the first quarter of 2013 development activities. Net borrowings increased the outstanding borrowings under our credit agreement from $237 million at December 31, 2012 to $291.4 million at March 31, 2013.

        During the first quarter of 2012, we received net cash of $13.0 million from financing activities, consisting primarily of net borrowings under our credit agreement.

        During 2012, we received net cash of $228.8 million from financing activities, including $122.9 million of net proceeds from the issuance of our former second lien term loan, which were used to replace outstanding borrowings under our credit agreement, net borrowings of $67 million under our credit agreement and $40.2 million of partner contributions, which were used primarily to finance 2012 acquisitions. Net borrowings increased the outstanding borrowings under our credit agreements from $170 million at December 31, 2011 to $237 million at December 31, 2012.

        During 2011, we received net cash of $471.6 million from financing activities, including net borrowings of $170 million under our credit agreement and $304.0 million of partner contributions.

    Liquidity

        Our primary sources of liquidity historically have been internally generated cash flows, the borrowing capacity under our credit agreement and partner contributions, including from our equity sponsor, the Apollo Funds. Since we operate a majority of our wells, we also have the ability to adjust our capital expenditures. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and expected future availability under our credit agreement after giving effect to the issuance of the securities offered hereby and the application of the estimated net proceeds from

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this offering as described under "Use of Proceeds" will be sufficient to fund our operations and planned capital expenditures for at least the next 12 months. However, should commodity prices decline for an extended period of time or the capital/credit markets become constrained, the borrowing capacity under our credit agreement could be adversely affected. In the event of a reduction in the borrowing base under our credit agreement, we may be required to prepay some or all of our indebtedness, which would adversely affect our capital expenditure program. In addition, because wells funded in the next 12 months represent only a small percentage of our identified net drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.

        In 2013, we plan to invest approximately $350 million of development capital. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our credit agreement.

        Internally generated cash flows.    Our internally generated cash flows, results of operations and financing for our operations are largely dependent on oil, natural gas and NGLs prices. During the first quarter of 2013, our average realized oil and NGLs prices decreased by 15% and 26%, respectively, as compared to the first quarter of 2012, while our average realized natural gas price increased by 21%. During 2012, our average realized oil, natural gas and NGLs prices decreased by 5%, 23% and 25%, respectively, as compared to 2011. Realized commodity prices fluctuate widely in response to changing market forces. If commodity prices decline or we experience a significant widening of our differentials to NYMEX prices, then our results of operations, cash flows from operations and borrowing base under our credit agreement may be adversely impacted. Prolonged periods of lower commodity prices or sustained wider differentials to NYMEX prices could cause us to not be in compliance with financial covenants under our credit agreement and thereby affect our liquidity. To offset reduced cash flows in a lower commodity price environment, we have established a portfolio of commodity derivative contracts consisting primarily of oil swaps that will provide stable cash flows on a portion of our oil production. As of March 31, 2013, our hedged oil volumes for 2013, 2014 and 2015 represent 99%, 96% and 21%, respectively, of our March 2013 oil production at weighted average prices of $94.18, $92.76 and $93.18, respectively. An increase in oil prices above the ceiling prices in our commodity derivative contracts limits cash inflows because we would be required to pay our counterparties for the difference between the market price for oil and the ceiling price of the commodity derivative contract resulting in a loss. Please read "—Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our commodity derivative contracts.

        Credit agreement.    We are a party to an amended and restated credit agreement dated March 19, 2013, which we refer to as our credit agreement, which matures on March 19, 2018. Our credit agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries. The aggregate amount of the commitments of the lenders under our credit agreement is $1.0 billion. Availability under our credit agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations.

        As of March 31, 2013, the borrowing base was $360 million and there were $291.4 million of outstanding borrowings, $68.6 million of borrowing capacity and no outstanding letters of credit under our credit agreement. In conjunction with the offering of our senior notes in April 2013 as discussed below, the borrowing base under our credit agreement was reduced to $267.5 million. We used a portion of the net proceeds from the offering of the senior notes to reduce the outstanding borrowings under our credit agreement. In May 2013, we amended our credit agreement to, among other things, increase the borrowing base to $320 million. As of July 22, 2013, there were $72 million of outstanding borrowings under our credit agreement.

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        Obligations under our credit agreement are secured by a first-priority security interest in substantially all of our proved reserves and in the equity interests of our operating subsidiaries. In addition, obligations under our credit agreement are guaranteed by our operating subsidiaries.

        Loans under our credit agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under our credit agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under our credit agreement bear interest at the base rate plus the applicable margin indicated in the following table. We also incur a quarterly commitment fee on the unused portion of our credit agreement indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base
  Unused
Commitment
Fee
  Applicable
Margin for
Eurodollar
Loans
  Applicable
Margin for
Base Rate
Loans
 

Less than or equal to .30 to 1

    0.375 %   0.50 %   1.50 %

Greater than .30 to 1 but less than or equal to .60 to 1

    0.375 %   0.75 %   1.75 %

Greater than .60 to 1 but less than or equal to .80 to 1

    0.50 %   1.00 %   2.00 %

Greater than .80 to 1 but less than or equal to .90 to 1

    0.50 %   1.25 %   2.25 %

Greater than .90 to 1

    0.50 %   1.50 %   2.50 %

        The "Eurodollar rate" for any interest period (either one, two, three or six months, as selected by us) is the rate equal to the LIBOR for deposits in dollars for a similar interest period. The "Base Rate" is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its "prime rate"; (2) the federal funds effective rate plus 0.5%; or (3) except during a "LIBOR Unavailability Period," the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0%.

        Any outstanding letters of credit reduce the availability under our credit agreement. Borrowings under our credit agreement may be repaid from time to time without penalty.

        Our credit agreement contains customary covenants including, among others, the following:

    a prohibition against incurring debt, subject to permitted exceptions;

    a restriction on creating liens on our assets and the assets of our operating subsidiaries, subject to permitted exceptions;

    restrictions on merging and selling assets outside the ordinary course of business;

    restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;

    a requirement that we maintain a ratio of consolidated total debt to EBITDAX (as defined in our credit agreement and as presented under "Summary Consolidated Financial, Reserve and Operating Data—Non-GAAP Financial Measures—Adjusted EBITDA") of not more than 4.75 to 1.0 (which ratio changes to 4.5 to 1.0 beginning with the quarter ended June 30, 2014); and

    a provision limiting commodity derivative contracts to a volume not exceeding 85% of projected production from proved reserves for a period not exceeding 66 months from the date the commodity derivative contract is entered into.

        Our credit agreement contains customary events of default, including our failure to comply with our financial ratios described above, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding

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under our credit agreement to be immediately due and payable, which would materially and adversely affect our financial condition and liquidity.

        Certain of the lenders underwriting our credit agreement are also counterparties to our commodity derivative contracts. Please read "—Quantitative and Qualitative Disclosures About Market Risk" for additional discussion.

        We expect to reduce outstanding borrowings under our credit agreement with a portion of the net proceeds from this offering.

        Senior notes.    In April 2013, we issued $500 million aggregate principal amount of 73/8% senior notes due 2021. The net proceeds from the senior notes offering were used to repay a portion of the outstanding borrowings under our credit agreement, to repay in full and terminate our former second lien term loan, to make a $75 million distribution to Class A limited partners of Athlon Holdings LP and for general corporate purposes. The indenture governing the senior notes contains covenants, including, among other things, covenants that restrict our ability to:

    make distributions, investments or other restricted payments if our fixed charge coverage ratio is less than 2.0 to 1.0;

    incur additional indebtedness if our fixed charge coverage ratio would be less than 2.0 to 1.0; and

    create liens, sell assets, consolidate or merge with any other person or engage in transactions with affiliates.

These covenants are subject to a number of important qualifications, limitations and exceptions. In addition, the indenture contains other customary terms, including certain events of default upon the occurrence of which the senior notes may be declared immediately due and payable.

        Under the indenture, starting on April 15, 2016, we will be able to redeem some or all of the senior notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption. Prior to April 15, 2016, we will be able, at our option, to redeem up to 35% of the aggregate principal amount of the senior notes at a price of 107.375% of the principal thereof, plus accrued and unpaid interest to the date of redemption, with an amount equal to the net proceeds from certain equity offerings. In addition, at our option, prior to April 15, 2016, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes, plus an "applicable premium," plus accrued and unpaid interest to the date of redemption. If a change of control occurs on or prior to July 15, 2014, we may redeem all, but not less than all, of the notes at 110% of the principal amount thereof plus accrued and unpaid interest to, but not including, the redemption date. Certain asset dispositions will be triggering events that may require us to repurchase all or any part of a noteholder's notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to but excluding the date of repurchase. Interest on the senior notes is payable in cash semi-annually in arrears, commencing on October 15, 2013, through maturity.

        Capitalization.    At March 31, 2013, we had total assets of $916.5 million and total capitalization of $849.8 million, of which 51% was represented by equity and 49% by long-term debt. At December 31, 2012, we had total assets of $852.3 million and total capitalization of $782.9 million, of which 54% was represented by equity and 46% by long-term debt. The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

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Changes in Prices

        Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms are affected by changes in commodity prices, which can fluctuate significantly. The following table provides our average realized prices for the periods indicated:

 
  Three months ended March 31,   Year ended December 31,  
 
  2013   2012   2012   2011  

Average realized prices:

                         

Oil ($/Bbl) (excluding impact of cash settled derivatives)

  $ 84.23   $ 99.29   $ 87.90   $ 92.08  

Oil ($/Bbl) (after impact of cash settled derivatives)

    83.65     89.53     87.16     87.16  

Natural gas ($/Mcf)

    3.27     2.71     2.66     3.46  

NGLs ($/Bbl)

    31.34     42.48     34.65     45.96  

Combined ($/BOE) (excluding impact of cash settled derivatives)

    61.08     71.05     60.91     68.13  

Combined ($/BOE) (after impact of cash settled derivatives)

    60.73     65.28     60.50     65.29  

        Increases in commodity prices may be accompanied by or result in: (1) increased development costs, as the demand for drilling operations increases; (2) increased severance taxes, as we are subject to higher severance taxes due to the increased value of hydrocarbons extracted from our wells; and (3) increased LOE, such as electricity costs, as the demand for services related to the operation of our wells increases. Decreases in commodity prices can have the opposite impact of those listed above and can result in an impairment charge to our oil and natural gas properties.

Critical Accounting Policies and Estimates

        Preparing financial statements in accordance with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Estimates and assumptions are based on information available prior to financial statements being issued. Due to the nature of these estimates, new facts or circumstances may arise resulting in revised estimates which differ from these estimates. Management considers an accounting estimate to be critical if it requires assumptions that have a high degree of subjectivity and judgment to account for outcomes that are highly uncertain and the impact of these estimates and assumptions is material to our consolidated results of operations or financial condition. Management has identified the following critical accounting policies and estimates.

    Oil and Natural Gas Reserves

        Our estimates of proved reserves are based on the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions and operating methods. Our independent petroleum engineers, CG&A, prepare a reserve and economic evaluation of all of our properties on a well-by-well basis. The accuracy of reserve estimates is a function of the:

    quality and quantity of available data;

    interpretation of that data;

    accuracy of various mandated economic assumptions; and

    judgment of the independent reserve engineer.

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        Estimating reserves is subjective and actual quantities of oil and natural gas ultimately recovered can differ from estimates for many reasons. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, the property's fair value and our DD&A rate.

        Our independent petroleum engineers, CG&A, estimate our proved reserves annually on December 31. This results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter production. We internally estimate reserve additions and reclassifications of reserves from unproved to proved at the end of the first, second and third quarters for use in determining a DD&A rate for the respective quarter.

    Method of Accounting for Oil and Natural Gas Properties

        We apply the provisions of the "Extractive Activities—Oil and Gas" topic of the Financial Accounting Standards Board's ("FASB") Accounting Standards Codification ("ASC"). We use the full cost method of accounting for our oil and natural gas properties. Under this method, costs directly associated with the acquisition, exploration and development of reserves are capitalized into a full cost pool. Capitalized costs are amortized using a unit-of-production method. Under this method, the provision for DD&A is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period.

        Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties primarily consist of acquisition and leasehold costs as well as development costs for wells in progress for which a determination of the existence of proved reserves has not been made. These costs are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property, upon impairment of a lease or immediately upon determination that the well is unsuccessful. Costs of seismic data that cannot be directly associated to specific unproved properties are included in the full cost pool as incurred, otherwise, they are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

        Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.

        Natural gas volumes are converted to BOE at the rate of six Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

        We capitalize interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense.

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    Impairment

        Unevaluated properties are assessed periodically, at least annually, for possible impairment. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.

        Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated DD&A, less related deferred income taxes may not exceed an amount equal to PV-10 plus the lower of cost or fair value of unevaluated properties, plus estimated salvage value, less the related tax effects (the "ceiling limitation"). A ceiling limitation is calculated at the end of each quarter. If total capitalized costs, net of accumulated DD&A, less related deferred income taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts equity in the period of occurrence and typically results in lower DD&A expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

        The ceiling limitation calculation is prepared using the 12-month first-day-of-the-month oil and natural gas average prices, as adjusted for basis or location differentials, held constant over the life of the reserves ("net wellhead prices"). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. We use commodity derivative contracts to mitigate the risk against the volatility of oil and natural gas prices. Commodity derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows. We have not designated any of our commodity derivative contracts as cash flow hedges and therefore have excluded commodity derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.

    Asset Retirement Obligations

        We apply the provisions of the "Asset Retirement and Environmental Obligations" topic of the ASC. We have obligations as a result of lease agreements and enacted laws to remove our equipment and restore land at the end of production operations. These asset retirement obligations are primarily associated with plugging and abandoning wells and land remediation. At the time a well is drilled or acquired, we record a separate liability for the estimated fair value of our asset retirement obligations, with an offsetting increase to the related oil and natural gas asset representing asset retirement costs. The cost of the related oil and natural gas asset, including the asset retirement cost, is included in our full cost pool. The estimated fair value of an asset retirement obligation is the present value of the expected future cash outflows required to satisfy the asset retirement obligations discounted at our credit-adjusted, risk-free interest rate at the time the liability is incurred. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

        Inherent to the present-value calculation are numerous estimates, assumptions and judgments, including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions affect the present value of the abandonment liability, we make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. These revisions result in prospective changes to DD&A expense and accretion of the discounted abandonment liability.

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    Revenue Recognition

        Revenues from the sale of oil, natural gas and NGLs are recognized when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller's price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured. Because final settlement of our hydrocarbon sales can take up to two months, the estimated sales volumes and prices are estimated and accrued using information available at the time the revenue is recorded.

    Derivatives

        We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our oil production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions.

        We apply the provisions of the "Derivatives and Hedging" topic of the ASC, which requires each derivative instrument to be recorded at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. We elected not to designate our current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings.

        We enter into commodity derivative contracts for the purpose of economically hedging the price of our anticipated oil production even though we do not designate the derivatives as hedges for accounting purposes. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities in the consolidated statements of cash flows. During 2011 and 2012, we entered into commodity derivative contracts all of which were for the purpose of economically hedging our anticipated oil production.

        Cash flows relating to commodity derivative contracts that were entered into prior to us commencing oil and natural gas operations in January 2011 are classified as investing activities in the consolidated statements of cash flows.

        As required by GAAP, we utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities. Fair values of swaps are estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services. Our collars and puts are average value options. Settlement is determined by the average underlying price over a predetermined period of time. We use observable inputs in an option pricing valuation model to determine fair value such as: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (4) appropriate volatilities.

        We adjust the valuations from the valuation model for nonperformance risk. For commodity derivative contracts which are in an asset position, we use the counterparty's credit default swap rating. For commodity derivative contracts which are in a liability position, we use the average credit default swap rating of our peer companies with similar credit profiles as currently we do not have our own credit default swap rating.

New Accounting Pronouncements

        In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities" and in January 2013 issued ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities." These ASUs created new disclosure requirements regarding the nature

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of an entity's rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements are required, irrespective of whether the entity has elected to offset those instruments in the balance sheet. These ASUs were effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs did not impact our financial condition, results of operations or liquidity.

Emerging Growth Company

        The JOBS Act permits an "emerging growth company" like us to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We have elected to "opt out" of this provision and, as a result, we will comply with new or revised accounting standards as required when they are adopted. This decision to opt out of the extended transition period is irrevocable.

Quantitative and Qualitative Disclosures About Market Risk

        The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

    Derivative policy

        Due to the volatility of commodity prices, we enter into various derivative instruments to manage and reduce our exposure to price changes. We primarily utilize WTI crude oil swaps that establish a fixed price for the production covered by the swaps. We also have employed WTI crude oil options (including puts and collars) to further mitigate our commodity price risk. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in lower net cash inflows in times of higher oil prices than we would otherwise have, had we not utilized these instruments, management believes that the resulting reduced volatility of cash flow resulting from use of derivatives is beneficial.

    Counterparties

        At March 31, 2013, we had committed 10% or greater (in terms of fair market value) of our oil derivative contracts in asset positions to the following counterparties:

Counterparty
  Fair Market
Value of Oil
Derivative
Contracts
Committed
 
 
  (in thousands)
 

BNP Paribas

  $ 1,824  

        We do not require collateral from our counterparties for entering into financial instruments, so in order to mitigate the credit risk of financial instruments, we enter into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in two ways: (1) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (2) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

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        The counterparties to our commodity derivative contracts are composed of six institutions, all of which are rated A- or better by Standard & Poor's and Baa2 or better by Moody's and five of which are lenders under our credit agreement.

    Commodity price sensitivity

        Commodity prices are often subject to significant volatility due to many factors that are beyond our control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators and geopolitical events such as wars or natural disasters. We manage oil price risk with swaps, puts and collars. Swaps provide a fixed price for a notional amount of sales volumes. Puts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. This participation is limited by a ceiling price specified in the contract.

        The following table summarizes our open commodity derivative contracts as of March 31, 2013:

Period
  Average
Daily Floor
Volume
  Weighted-
Average
Floor Price
  Average
Daily Cap
Volume
  Weighted-
Average
Cap Price
  Average
Daily Swap
Volume
  Weighted-
Average
Swap Price
  Asset
(Liability)
Fair
Market
Value
 
 
  (Bbl)
  (per Bbl)
  (Bbl)
  (per Bbl)
  (Bbl)
  (per Bbl)
  (in thousands)
 

2013

    150   $ 75.00     150   $ 105.95     6,000   $ 94.66   $ (3,474 )

2014

                    5,950     92.76     130  

2015

                    1,300     93.18     1,782  
                                           

                                      $ (1,562 )
                                           

        We are also a party to Midland-Cushing basis differential swaps for 5,000 Bbls/D at $1.20/Bbl for April through December 2013. At March 31, 2013, the fair value of these contracts was a liability of approximately $1.2 million.

        As stated above under "—Critical Accounting Policies and Estimates—Derivatives," we elected not to designate our derivative contracts as hedges and therefore changes in fair value of these instruments are recognized in earnings. As of March 31, 2013, the fair market value of our oil derivative contracts was a net liability of $2.7 million. Based on our open commodity derivative positions at March 31, 2013, a 10% increase in NYMEX prices for oil would increase our net commodity derivative liability by approximately $12.5 million, while a 10% decrease in NYMEX prices for oil would change our net commodity derivative liability to a net commodity derivative asset of approximately $10.1 million.

    Interest rate sensitivity

        At March 31, 2013, we had outstanding debt of $416.4 million, all of which is subject to floating market rates of interest that are linked to the Eurodollar rate. At this level of floating rate debt, if the Eurodollar rate increased 10%, we would incur an additional $1.7 million of interest expense per year, and if the Eurodollar rate decreased 10%, we would incur $1.7 million less.

Internal Controls and Procedures

        We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC.

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BUSINESS

General

        We are an independent exploration and production company focused on the acquisition, development and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin. The Permian Basin spans portions of Texas and New Mexico and is composed of three primary sub-basins: the Delaware Basin, the Central Basin Platform and the Midland Basin. All of our properties are located in the Midland Basin. Our drilling activity is currently focused on the low-risk vertical development of stacked pay zones, including the Spraberry, Wolfcamp, Cline, Strawn, Atoka and Mississippian formations, which we refer to collectively as the Wolfberry play. We are a returns-focused organization and have targeted the Wolfberry play in the Midland Basin because of its favorable operating environment, consistent reservoir quality across multiple target horizons, long-lived reserve characteristics and high drilling success rates.

        We were founded in August 2010 by a group of former executives from Encore Acquisition Company following its acquisition by Denbury Resources, Inc. With an average of approximately 20 years of industry experience and over 10 years of history working together, our founding management has a proven track record of working as a team to acquire, develop and exploit oil and natural gas reserves in the Permian Basin as well as other resource plays in North America.

        Our acreage position was 124,925 gross (98,348 net) acres at May 31, 2013, which we group into three primary areas based on geographic location within the Midland Basin: Howard, Midland & Other and Glasscock. From the time we began operations in January 2011 through May 31, 2013, we have operated up to eight vertical drilling rigs simultaneously and have drilled 230 gross vertical Wolfberry wells with a 99% success rate across all three areas. This activity has allowed us to identify and de-risk our multi-year inventory of 4,902 gross (3,857 net) vertical drilling locations, while also identifying 1,079 gross (931 net) horizontal drilling locations in specific areas based on geophysical and technical data. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify additional horizontal drilling locations.

        The following table summarizes our leasehold position and identified net drilling locations by primary geographic area as of May 31, 2013:

 
   
   
  Identified Drilling Locations1  
 
   
   
  Vertical    
 
 
  Acreage    
 
 
  Net
40-acre2
  Net
20-acre
  Net
Total
  Drilling
Inventory3
(years)
  Net
Horizontal4
 
 
  Gross   Net  

Howard

    69,661     51,556     1,140     1,291     2,431     37     403  

Midland & Other

    36,694     33,709     390     414     804     20     316  

Glasscock

    18,570     13,083     267     355     622     24     212  
                                 

Total

    124,925     98,348     1,797     2,060     3,857     30     931