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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on January 24, 2014

Registration No. 333-          

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



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



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 Stock, par value $0.01 per share

  13,800,000   $27.87   $384,606,000   $49,537.26

 

(1)
Includes shares of common stock that may be sold to cover the exercise of an option to purchase additional shares granted to the underwriters.

(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) under the Securities Act of 1933, as amended. The price for the 13,800,000 shares being registered hereby is based on a price of $27.87, which is the average of the high and low trading prices per share as reported by the New York Stock Exchange on January 21, 2014.

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

   


Table of Contents

The information in this prospectus is not complete and may be changed. The 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 we and the selling stockholders are 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 JANUARY 24, 2014

PROSPECTUS

LOGO

12,000,000 Shares

Athlon Energy Inc.

Common Stock
$      per share



        The selling stockholders are offering 12,000,000 shares of our common stock. We will not receive any of the proceeds from the sale of the shares by the selling stockholders. Our common stock is listed on the New York Stock Exchange under the symbol "ATHL." The last reported closing sale price of our common stock on January 23, 2014 was $28.58 per share.

        The selling stockholders identified in this prospectus have granted the underwriters an option to purchase, on the same terms and conditions as set forth below, up to an additional 1,800,000 shares of common stock to cover over-allotments within 30 days from the date of this prospectus. We will not receive any of the proceeds from the sale of shares by the selling stockholders if the underwriters exercise their option to purchase 1,800,000 additional shares of common stock.



        Investing in our common stock involves risks. See "Risk Factors" beginning on page 20.

        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
Public Offering Price   $   $
Underwriting Discounts and Commissions(1)   $   $
Proceeds to the selling stockholders (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                  , 2014 through the book-entry facilities of The Depository Trust Company.



Citigroup   Goldman, Sachs & Co.



                  , 2014


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TABLE OF CONTENTS

Prospectus Summary

  1

The Offering

 
10

Summary Consolidated Financial, Reserve and Operating Data

 
12

Risk Factors

 
20

Cautionary Note Regarding Forward-Looking Statements

 
51

Use of Proceeds

 
53

Market Price of Our Common Stock

 
53

Dividend Policy

 
53

Capitalization

 
54

Selected Historical Consolidated Financial Data

 
55

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

 
56

Business

 
86

Management

 
111

Certain Relationships and Related Party Transactions

 
130

Corporate Reorganization

 
136

Principal and Selling Stockholders

 
138

Description of Capital Stock

 
140

Shares Eligible for Future Sale

 
147

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

 
149

Underwriting (Conflicts of Interest)

 
153

Legal Matters

 
160

Experts

 
160

Where You Can Find More Information

 
160

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. We, the underwriters and the selling stockholders have not authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. The selling stockholders 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.

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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 our 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 the selling stockholders and that the New Holdings Units subject to the terms of the exchange agreement are not exchanged for shares of our common stock.

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 primarily 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 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 128,306 gross (101,723 net) acres at September 30, 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 September 30, 2013, we have operated up to eight vertical drilling rigs simultaneously and have drilled 293 gross operated vertical Wolfberry wells and one gross operated horizontal Wolfcamp well with a 99% success rate. This activity has allowed us to identify and de-risk our multi-year inventory of 4,890 gross (3,938 net) vertical drilling locations, while also identifying 1,047 gross (932 net) horizontal drilling locations in specific areas based on geophysical and technical data, as of September 30, 2013. 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 vertical drilling locations by primary geographic area as of September 30, 2013:

 
   
   
  Identified Vertical Drilling Locations(1)  
 
  Acreage  
 
  Net
40-acre(2)
  Net
20-acre
   
  Drilling
Inventory(3)
(years)
 
 
  Gross   Net   Net Total  

Howard

    74,128     54,902     1,163     1,353     2,516     35  

Midland & Other

    36,573     33,709     388     411     799     19  

Glasscock

    17,605     13,112     261     362     623     27  
                             

Total

    128,306     101,723     1,812     2,126     3,938     29  
                             

(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.

        In addition, we have identified 1,047 gross (932 net) horizontal drilling locations targeting Wolfcamp A, Wolfcamp B, Wolfcamp C and Cline intervals, which comprise 320 gross (285 net), 361 gross (325 net), 135 gross (126 net) and 231 gross (196 net) locations, respectively. This represents a drilling inventory of 44 years based on a two-rig horizontal drilling program.

        Since our inception, we have completed two significant acquisitions. At the time of each acquisition, based on internal engineering estimates, these properties collectively contributed approximately 3,000 BOE/D of production and approximately 35.5 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 September 30, 2013, we have drilled 293 gross operated vertical Wolfberry wells and one gross operated horizontal Wolfcamp wells with a 99% success rate and grown our production to 12,960 BOE/D for the third quarter of 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 expect our drilling capital expenditures to be $380 million to $390 million, plus an additional $15 million for leasing, infrastructure and capital workovers, and to drill 169 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells. We currently operate eight vertical drilling rigs and one horizontal drilling rig. In 2014, we intend to expand to a two-rig horizontal drilling program.

        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

 

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composed of 597 gross (560 net) potential vertical drilling locations. The following table provides information regarding our proved reserves as of December 31, 2012:

 
  Estimated Total Proved Reserves  
 
  Oil
(MMBbls)
  NGLs
(MMBbls)
  Natural
Gas
(Bcf)
  Total
(MMBOE)
  % Liquids(1)   PV-10(2)
(in millions)
 

Howard

    20.2     7.3     36.3     33.5     82 % $ 365.4  

Midland & Other

    17.6     8.3     44.7     33.3     78 %   337.0  

Glasscock

    11.6     3.7     22.7     19.2     80 %   164.2  
                             

Total

    49.4     19.3     103.7     86.0     80 % $ 866.6  
                             

(1)
Includes 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."

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 expect our drilling capital expenditures to be $380 million to $390 million, plus an additional $15 million for leasing, infrastructure and capital workovers, and to drill 169 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells.

    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.

    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 began to supplement our vertical drilling with

 

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      horizontal drilling in circumstances where we believed that horizontal drilling offered competitive rates of return. We plan to add a second horizontal rig in 2014.

    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 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 on hand, cash flows from operating activities and availability under our credit agreement to be sufficient to fund our capital expenditures and other obligations necessary to execute our business plan in 2014. 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.

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 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 December 31, 2013, we had 27 engineering, land and geosciences technical 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. 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.

 

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    De-risked Midland Basin acreage position with multi-year vertical drilling inventory.  Since our management team commenced our development program in January 2011 through September 30, 2013, we have drilled 293 gross operated vertical Wolfberry wells and one gross operated horizontal Wolfcamp well 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 September 30, 2013, we have identified 2,268 gross (1,812 net) vertical drilling locations on 40-acre spacing and an additional 2,622 gross (2,126 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 4,890 gross (3,938 net) identified drilling locations represent 29 years of drilling inventory. 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 formation is present across portions of our leasehold position. Based on vertical well control information from our operations and the operations of offset operators as of September 30, 2013, we have identified 320 gross (285 net) horizontal drilling locations in the Wolfcamp A formation, 361 gross (325 net) horizontal drilling locations in the Wolfcamp B formation, 135 gross (126 net) horizontal drilling locations in the Wolfcamp C formation and 231 gross (196 net) horizontal drilling locations in the Cline 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. In the second half of 2013, we began to supplement our vertical drilling with horizontal drilling in circumstances where we believed that horizontal drilling offered competitive rates of return. We plan to add a second horizontal rig in 2014.

    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

    Initial Public Offering

        On August 7, 2013, we completed our initial public offering of 15,789,474 shares of our common stock at $20.00 per share. Additionally, on August 7, 2013, the underwriters closed their option to purchase an additional 2,348,421 shares of common stock at a price of $20.00 per share. Our common stock began trading on the New York Stock Exchange (the "NYSE") on August 2, 2013 under the symbol "ATHL." Following the closing of our initial public offering, common stock held by public holders represented approximately 22.1% of our outstanding common stock.

 

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        The net proceeds to us from the initial public offering were approximately $295.6 million, after deducting underwriting discounts and commissions and offering expenses. Approximately $72 million of the net proceeds were used to reduce outstanding indebtedness under our credit agreement and the remainder was used to provide additional liquidity for use in our drilling program and other corporate purposes.

    Fourth Quarter and Full-Year 2013 Production

        The following table provides our production volumes for the periods indicated:

 
  Three months ended December 31,   Year ended December 31,  
 
  2013   2012   % Change   2013   2012   % Change  

Total production volumes:

                                     

Oil (MBbls)

    819     447     83 %   2,682     1,457     84 %

Natural gas (MMcf)

    1,453     998     46 %   4,927     3,163     56 %

NGLs (MBbls)

    290     188     54 %   954     595     60 %

Combined (MBOE)

    1,351     801     69 %   4,458     2,579     73 %

Average daily production volumes:

                                     

Oil (Bbls/D)

    8,905     4,855     83 %   7,349     3,981     85 %

Natural gas (Mcf/D)

    15,791     10,843     46 %   13,497     8,641     56 %

NGLs (Bbls/D)

    3,151     2,048     54 %   2,614     1,625     61 %

Combined (BOE/D)

    14,689     8,710     69 %   12,213     7,047     73 %

    Fourth Quarter and Full-Year 2013 Drilling

        During the three months ended December 31, 2013, we drilled 46 gross (45 net) operated vertical Wolfberry wells, while operating seven vertical drilling rigs. During 2013, we drilled 171 gross (165 net) operated vertical Wolfberry wells. We currently have two gross operated horizontal Wolfcamp wells on production and three gross operated horizontal Wolfcamp wells in varying stages of drilling and completion. Our first producing horizontal well achieved a peak 24-hour initial production ("IP") rate of 1,661 BOE/D (80% oil) and a 30-day IP rate of 1,200 BOE/D (77% oil). Our second producing horizontal well achieved a peak 24-hour IP rate of 2,078 BOE/D (78% oil) and a 20-day IP rate of 1,759 BOE/D (71% oil).

    Acquisition Update

        In January 2014, we entered into a purchase and sale agreement to acquire certain oil and natural gas properties and related assets consisting of 5,645 net acres in the Midland Basin of West Texas for $88 million in cash. The properties include approximately 750 BOE/D (60% oil) of production, 70 gross horizontal drilling locations, 58 gross producing vertical wells, 250 gross vertical drilling locations, 2.9 MMBOE of proved reserves based on internal reserve reports, and are 82% operated with a 72.5% average working interest. The acquisition, which is subject to customary closing conditions, is expected to close in February 2014 with a September 1, 2013 effective date and will be financed with cash on hand and borrowing capacity under our credit agreement.

        Since our IPO, we have added approximately 11,000 net acres, including the above mentioned acquisition. Our current total acreage position is approximately 109,000 net acres, entirely in the northern Midland Basin.

    2014 Outlook

        Our 2014 drilling capital budget is $595 million, plus an additional $20 million for infrastructure, leasing and capitalized workovers. During 2014, we expect to operate eight vertical drilling rigs and drill

 

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205 gross vertical Wolfberry wells. We also expect to add a second horizontal drilling rig in the second quarter of 2014 and drill 21 gross operated horizontal Wolfcamp wells during 2014.

        We expect our average daily production to be 16,200 to 16,800 BOE/D for the first quarter of 2014 and 19,750 to 20,750 BOE/D for 2014. For 2014, we expect direct LOE to average $6.35 to $6.85 per BOE, production, severance and ad valorem tax to be 6.5% to 7.0% of wellhead revenues and recurring cash general and administrative expenses to average $2.50 to $3.00 per BOE.

    Hedge Portfolio

        The following table summarizes our current open commodity derivative contracts, which are priced off NYMEX WTI crude oil index prices:

Period
  Average Daily
Swap Volume
  Weighted-Average
Swap Price
 
 
  (Bbl)
  (per Bbl)
 

Q1 2014

    8,606   $ 92.70  

Q2 2014

    8,950     92.71  

Q3 2014

    9,950     92.52  

Q4 2014

    9,950     92.52  

2015

    1,300     93.18  

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 did not exchange 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. At the closing of our initial public offering, the limited partnership agreement of Athlon Holdings LP was amended and restated to, among other things, modify Athlon Holdings 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 held Class A limited partner interests of Athlon Holdings LP now own New Holdings Units and entered into an exchange agreement under which (subject to the terms of the exchange agreement) they 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 are held by Athlon Energy Inc. Please read "Corporate Reorganization" and "Certain Relationships and Related Party Transactions—Exchange Agreement."

 

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        The diagram below sets forth our simplified organizational structure after giving effect to this offering. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us.

GRAPHIC


(1)
The Apollo Funds and the public stockholders will hold 48.8% and 38.8% of our shares of common stock, respectively, if the underwriters exercise in full their option to purchase additional shares of common stock from the selling stockholders.

(2)
Borrowing base of $525 million as of January 24, 2014.

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

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 September 30, 2013, Apollo had assets under management of approximately $113 billion in private equity, credit 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.

 

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        Upon completion of this public offering, the Apollo Funds will beneficially own approximately 50.9% of our common stock (or approximately 48.8% if the underwriters' option to purchase additional shares of common stock from the selling stockholders 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 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 the selling stockholders

  12,000,000 shares.

Common stock to be outstanding before and after the offering

 

82,129,089 shares.

New Holdings Units to be outstanding before and after the offering

 

83,984,652 units (1,855,563 of which will be exchangeable for 1,855,563 shares of our common stock).

Over-allotment option

 

The underwriters have a 30-day option to purchase 1,800,000 shares of common stock from the selling stockholders if the underwriters sell more than 12,000,000 shares in this offering.

Use of proceeds

 

We will not receive any proceeds from the sale of common stock by the selling stockholders.

 

Please read "Use of Proceeds" and "Principal and Selling Stockholders."

Dividend policy

 

We do not pay currently, and do not anticipate paying in the future, 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 20 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.

Trading symbol

 

"ATHL."

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, because the Apollo Funds, as selling stockholders, will 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. In accordance with that rule, the appointment of a "qualified independent underwriter" is not required in connection with this offering because a bona fide public market exists for our common stock. 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)."

 

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        The information above excludes 8,400,000 shares of common stock 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 for shares of our common stock, there would be a total of 83,984,652 shares of our common stock outstanding, 14.3% of which would be owned by purchasers in this offering (assuming the underwriters' option to purchase additional shares of common stock from the selling stockholders is not exercised).

 

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SUMMARY CONSOLIDATED FINANCIAL, RESERVE AND OPERATING DATA

        The following summary consolidated financial, reserve and operating data 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 our 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 from our audited consolidated financial statements, which are included elsewhere in this prospectus. We derived the summary historical consolidated balance sheet data as of September 30, 2013 and the historical consolidated statements of operations data and statements of cash flow data for the nine months ended September 30, 2013 and 2012 from our unaudited consolidated financial statements, which are included elsewhere in this prospectus.

 

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Summary Consolidated Financial Data

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (unaudited)
   
   
 
 
  (in thousands, except per share data)
 

Consolidated Statements of Operations Data:

                         

Revenues:

                         

Oil

  $ 175,934   $ 91,407   $ 128,081   $ 51,193  

Natural gas

    11,894     5,323     8,415     3,521  

NGLs

    20,508     14,379     20,615     10,967  
                   

Total revenues

    208,336     111,109     157,111     65,681  
                   

Expenses:

                         

Production:

                         

Lease operating

    23,774     17,846     25,503     13,328  

Production, severance and ad valorem taxes           

    13,380     7,617     10,438     4,727  

Processing, gathering and overhead

    169     55     84     60  

Depletion, depreciation and amortization

    62,022     37,770     54,456     19,747  

General and administrative

    13,543     7,212     9,678     7,724  

Contract termination fee

    2,408              

Acquisition costs

    180         876     9,519  

Derivative fair value loss (gain)

    21,331     (9,590 )   (9,293 )   7,959  

Accretion of discount on asset retirement obligations

    485     343     478     344  
                   

Total expenses

    137,292     61,253     92,220     63,408  
                   

Operating income

    71,044     49,856     64,891     2,273  
                   

Other income (expenses):

                         

Interest

    (26,595 )   (5,804 )   (9,951 )   (2,945 )

Other

    30     2     2     13  
                   

Total other expenses

    (26,565 )   (5,802 )   (9,949 )   (2,932 )
                   

Income (loss) before income taxes

    44,479     44,054     54,942     (659 )

Income tax provision

    6,805     1,546     1,928     470  
                   

Consolidated net income (loss)

    37,674     42,508     53,014     (1,129 )

Less: net income attributable to noncontrolling interest

    616              
                   

Net income (loss) attributable to stockholders

  $ 37,058   $ 42,508   $ 53,014   $ (1,129 )
                   

Net income (loss) per common share:

                         

Basic

  $ 0.53   $ 0.64   $ 0.80   $ (0.02 )

Diluted

  $ 0.53   $ 0.62   $ 0.78   $ (0.02 )

Weighted average common shares outstanding:

                         

Basic

    69,810     66,340     66,340     66,340  

Diluted

    71,666     68,196     68,196     66,340  

Consolidated Statements of Cash Flows Data:

                         

Cash provided by (used in):

                         

Operating activities

  $ 136,775   $ 62,754   $ 95,302   $ 18,872  

Investing activities

    (295,003 )   (186,900 )   (347,259 )   (465,475 )

Financing activities

    346,245     100,850     228,798     471,627  

Consolidated Balance Sheets Data:

                         

Cash and cash equivalents

  $ 196,888         $ 8,871   $ 32,030  

Total assets

    1,321,417           852,298     561,823  

Long-term debt

    500,000           362,000     170,000  

Total equity

    609,727           420,877     327,452  

Other Financial Data:

                         

Adjusted EBITDA(1)

  $ 153,784   $ 76,600   $ 111,160   $ 39,094  

Development capital

    278,318     188,776     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 Data(1):

             

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.

 

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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;

    Corporate reorganization costs;

    Acquisition costs;

    Advisory fees;

    Contract termination fees;

    Non-recurring IPO costs;

    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.

 

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        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):

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Consolidated net income (loss)

  $ 37,674   $ 42,508   $ 53,014   $ (1,129 )

Interest expense

    26,595     5,804     9,951     2,945  

Interest income

    (5 )   (2 )   (2 )   (13 )

Income taxes

    6,805     1,546     1,928     470  

Depletion, depreciation and amortization

    62,022     37,770     54,456     19,747  

Corporate reorganization costs

    661              

Acquisition costs

    180         876     9,519  

Advisory fees(1)

    500     493     493     411  

Contract termination fee(2)

    2,408              

Non-recurring IPO costs(3)

    2,251              

Non-cash equity-based compensation

    630     118     152     106  

Derivative fair value loss (gain)(4)

    21,331     (9,590 )   (9,293 )   7,959  

Net derivative settlements received (paid), adjusted for recovered premiums(5)

    (7,906 )   (2,485 )   (1,074 )   (2,734 )

Accretion of discount on asset retirement obligations

    485     343     478     344  

Other non-cash operating items(6)

    153     95     181     1,469  
                   

Adjusted EBITDA

  $ 153,784   $ 76,600   $ 111,160   $ 39,094  
                   

(1)
Represents the annual advisory fee paid to affiliates of Apollo pursuant to a Services Agreement. The Services Agreement was terminated in connection with our initial public offering. Please read "Certain Relationships and Related Party Transactions."

(2)
Represents the fee paid to affiliates of Apollo pursuant to the termination of the Services Agreement in connection with our initial public offering. Please read "Certain Relationships and Related Party Transactions."

(3)
Represents bonuses paid subsequent to the successful completion of our IPO and non-cash equity-based compensation related to the accelerated vesting of Athlon Holdings LP's Class B limited partner interests as a result of the IPO.

(4)
Represents total derivative loss (gain) reported in our consolidated statements of operations.

(5)
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).

(6)
Represents deferred rent expense and non-cash LOE.

 

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

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Adjusted EBITDA

  $ 153,784   $ 76,600   $ 111,160   $ 39,094  

Changes in working capital

    9,764     (8,380 )   (6,059 )   (6,752 )

Cash interest

    (22,472 )   (5,287 )   (8,850 )   (2,623 )

Corporate reorganization costs

    (661 )            

Acquisition costs

    (180 )       (876 )   (9,519 )

Non-cash LOE

                (1,159 )

Advisory fees(1)

    (500 )   (493 )   (493 )   (411 )

Contract termination fee(2)

    (2,408 )            

Cash non-recurring IPO costs(3)

    (1,082 )            

Amoritzation of derivative premiums paid

    530     314     420     242  
                   

Cash flows provided by operating activities

  $ 136,775   $ 62,754   $ 95,302   $ 18,872  
                   

(1)
Represents the annual advisory fee paid to affiliates of Apollo pursuant to a Services Agreement. The Services Agreement was terminated in connection with our initial public offering. Please read "Certain Relationships and Related Party Transactions."

(2)
Represents the fee paid to affiliates of Apollo pursuant to the termination of the Services Agreement in connection with our initial public offering. Please read "Certain Relationships and Related Party Transactions."

(3)
Represents bonuses paid subsequent to the successful completion of our IPO.

    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  
           

 

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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:

 
  Nine months
ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  

Total production volumes:

                         

Oil (MBbls)

    1,863     1,011     1,457     556  

Natural gas (MMcf)

    3,474     2,165     3,163     1,017  

NGLs (MBbls)

    664     407     595     239  

Combined (MBOE)

    3,106     1,778     2,579     964  

Average daily production volumes:

                         

Oil (Bbls/D)

    6,824     3,688     3,981     1,523  

Natural gas (Mcf/D)

    12,725     7,903     8,641     2,786  

NGLs (Bbls/D)

    2,433     1,484     1,625     654  

Combined (BOE/D)

    11,378     6,489     7,047     2,641  

Average realized prices:

                         

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

  $ 94.43   $ 90.46   $ 87.90   $ 92.08  

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

    90.19     88.00     87.16     87.16  

Natural gas ($/Mcf)

    3.42     2.46     2.66     3.46  

NGLs ($/Bbl)

    30.87     35.37     34.65     45.96  

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

    67.07     62.49     60.91     68.13  

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

    64.52     61.09     60.50     65.29  

Expenses (per BOE):

                         

Lease operating

  $ 7.65   $ 10.04   $ 9.89   $ 13.82  

Production, severance and ad valorem taxes

    4.31     4.27     4.05     4.90  

Depletion, depreciation and amortization

    19.97     21.24     21.11     20.48  

General and administrative

    4.42     4.06     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 Energy Inc. was formed in April 2013 and became the sole owner of Athlon Holdings LP and its subsidiaries, 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 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 September 30, 2013, approximately 49% 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 September 30, 2013, approximately 49% 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. In 2013, we expect our drilling capital expenditures to be $380 million to $390 million, plus

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an additional $15 million for leasing, infrastructure and capital workovers. 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 on hand, 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 2014 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 September 30, 2013, we have drilled a total of 293 gross (281 net) operated vertical wells and one gross (one net) operated horizontal well and participated in an additional 10 gross (3 net) non-operated wells. In total, 280 gross (264 net) of these wells were completed as producing wells and 3 gross (3 net) wells were abandoned as dry holes. At September 30, 2013, 21 gross (20 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 September 30, 2013, we had identified 2,268 gross (1,812 net) potential vertical drilling locations on our existing acreage based on 40-acre spacing and an additional 2,622 gross (2,126 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

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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.

        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. Please read "Business—Oil and Natural Gas Production Prices and Production Costs—Developed and Undeveloped Acreage" for information regarding our leasehold expirations. 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.

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. Risks that we may 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 may 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

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fracture stimulation stage. In 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.

        Our experience with horizontal drilling utilizing the latest drilling and completion techniques is limited. 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.

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 eight vertical drilling rigs and one horizontal drilling rig. In 2014, we intend to expand to a two-rig horizontal 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;

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    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 in July 2008. During the third quarter of 2013, WTI prompt month contract ranged from $97.99 to $110.53 per Bbl and the Henry Hub prompt month contract price of natural gas ranged from $3.23 to $3.81 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 September 30, 2013, the WTI prompt month contract price for crude oil was $102.33 per Bbl and the Henry Hub prompt month contract price of natural gas was $3.56 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. 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

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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. Currently, we have oil swaps covering 7,950 Bbls/D at a weighted-average price of $92.67 per Bbl for 2014 and 1,300 Bbls/D at a weighted-average price of $93.18 per Bbl for 2015. 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.

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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.

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.

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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. The information related to EURs for our horizontal wells is not based on reports of, or otherwise reviewed by, CG&A. These projections are based on management's review of initial horizontal well results and decline curve analysis and, as a result, contain significant assumptions that may turn out to be inaccurate. In addition, a substantial portion of our reserve estimates, including those related to our horizontal wells, 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.

        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

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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 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

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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 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

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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.

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

        As of December 31, 2013, we had a total of $500 million aggregate principal amount of 73/8% senior notes due 2021 outstanding and $525 million of unused 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 January 24, 2014, there were no outstanding borrowings under our credit agreement. 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 $525 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 products on a regional, national or worldwide basis. These companies may be able to pay more for

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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 significant disruption in the availability of our or third-party transportation facilities or other production

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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 third quarter of 2013, we estimate that we flared approximately 4.4 MMcfe/D, which included both residue gas and NGL production. We may flare additional gas from time to time.

        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 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

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Protection Agency (the "EPA") however, has 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. The EPA issued a Progress Report in December 2012 and a final draft is anticipated by 2014 for peer review and public comment. A committee of the U.S. House of Representatives also conducted an investigation of hydraulic fracturing practices. 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. In response to some of these challenges, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final amendment was finalized on August 2, 2013, and published in the Federal Register on September 23, 2013. This rule 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.

        On May 24, 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The revised proposed rule would continue to require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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 natural gas properties and any increased

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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 Commodity 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.

        From time to time legislative proposals are made that would, if enacted, make significant changes to U.S. tax laws. These proposed changes have included, among others, 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. Such 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.

        The EPA has adopted two sets of related rules, one of which regulates 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.

        Several states or geographic regions have adopted legislation and regulations to reduce emissions of GHGs. 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.

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        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 are 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 required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2012 (the "Sarbanes-Oxley Act"). 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 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.

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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, the Apollo Funds will beneficially own in the aggregate approximately 50.9% of the combined voting power of our common stock (or approximately 48.8% if the underwriters option to purchase additional shares of common stock from the selling stockholders is exercised in full). As a result, the Apollo Funds will be able to exercise significant control over 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 stockholders agreement that we entered into in connection with our initial public offering provides 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

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

        The Apollo Funds currently control, and after this offering, assuming the underwriters do not exercise their option to purchase additional shares, will continue to control, a majority of our voting common stock. As a result, we 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.

        We utilize certain of these exemptions. As a result, we do not have a majority of independent directors nor does our nominating and corporate governance and compensation committees consist entirely of independent directors, and we are not 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.

Following this offering, if the underwriters exercise in full their option to purchase additional shares, we will no longer be a "controlled company" under the meaning of the NYSE rules and, as a result, will no longer qualify for exemptions from certain corporate governance requirements.

        We are listed on the NYSE and are therefore subject to the NYSE's corporate governance rules. As a result of this offering, we may no longer be a "controlled company" within the meaning of the NYSE corporate governance standards. Pursuant to the requirements of the NYSE rules, within one year after the completion of this offering, if the underwriters exercise in full their option to purchase additional shares, our Compensation Committee and Nominating and Corporate Governance Committee must be composed entirely of "independent directors" (as defined by the NYSE rules), and

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a majority of the directors on our board must be independent. Our board of directors currently consists of seven directors, two of whom are independent. During the phase-in period granted by the NYSE rules, our stockholders will not have the same protections afforded to stockholders of companies that are subject to all NYSE corporate governance rules. If, within one year of the completion of this offering, assuming the underwriters exercise in full their option to purchase additional shares, we do not have additional independent directors on our board of directors, Compensation Committee and Nominating and Corporate Governance Committee, we will not be in compliance with the NYSE corporate governance rules and may be subject to enforcement actions by the NYSE.

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

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

    permits 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."

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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.

If the price of our common stock fluctuates significantly, your investment could lose value.

        Although our common stock is listed on the NYSE, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, 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. 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;

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    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, 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 82,129,089 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 90 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.

        We filed 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 adopted upon the completion of our initial public 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 90 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

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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.

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 Delaware General Corporation Law (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

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    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.

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

        Our amended and restated certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder's ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons.

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


MARKET PRICE OF OUR COMMON STOCK

        Our common stock began trading on the NYSE under the symbol "ATHL" on August 2, 2013. Prior to that, there was no public market for our common stock. The table below sets forth, for the periods indicated, the high and low sales prices per share of our common stock since August 2, 2013.

Period
  High   Low  

Third Quarter 2013(1)

  $ 33.98   $ 25.25  

Fourth Quarter 2013

  $ 34.59   $ 26.91  

First Quarter 2014 (through January 23, 2014)

  $ 30.37   $ 26.97  

(1)
For the period from August 2, 2013 through September 30, 2013.

        On January 23, 2014, the closing price of our common stock was $28.58 per share. As of December 31, 2013, we had approximately 50 holders of record of our common stock. This number excludes owners for whom common stock may be held in "street" name.


DIVIDEND POLICY

        We have never declared or paid any cash dividends to holders of our common stock. We currently intend to retain all available funds, 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 our cash and capitalization as of September 30, 2013:

        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.

 
  (in thousands)
 

Cash and cash equivalents

  $ 196,888  
       

Debt:

       

Credit agreement

  $  

73/8% senior notes due 2021

    500,000  
       

Total debt

    500,000  
       

Stockholders' equity:

       

Preferred stock, $0.01 par value; 50,000,000 shares authorized, no shares issued and outstanding

     

Common stock, $0.01 par value; 500,000,000 shares authorized; 82,129,089 shares issued and outstanding

    821  

Additional paid-in capital

    588,583  

Retained earnings

    10,278  
       

Total stockholders' equity

    599,682  

Noncontrolling interest

    10,045  
       

Total equity

    609,727  
       

Total capitalization

  $ 1,109,727  
       

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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, our audited consolidated financial statements 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 September 30, 2013 and the consolidated statements of operations data and statements of cash flow data for the nine months ended September 30, 2013 and 2012 are derived from, and qualified by reference to, our unaudited consolidated financial statements 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.

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (unaudited)
   
   
 
 
  (in thousands, except per share amounts)
 

Consolidated Statements of Operations Data:

                         

Revenues:

                         

Oil

  $ 175,934   $ 91,407   $ 128,081   $ 51,193  

Natural gas

    11,894     5,323     8,415     3,521  

NGLs

    20,508     14,379     20,615     10,967  
                   

Total revenues

    208,336     111,109     157,111     65,681  
                   

Expenses:

                         

Production:

                         

Lease operating

    23,774     17,846     25,503     13,328  

Production, severance and ad valorem taxes

    13,380     7,617     10,438     4,727  

Processing, gathering and overhead

    169     55     84     60  

Depletion, depreciation and amortization

    62,022     37,770     54,456     19,747  

General and administrative

    13,543     7,212     9,678     7,724  

Contract termination fee

    2,408              

Acquisition costs

    180         876     9,519  

Derivative fair value loss (gain)

    21,331     (9,590 )   (9,293 )   7,959  

Accretion of discount on asset retirement obligations

    485     343     478     344  
                   

Total expenses

    137,292     61,253     92,220     63,408  
                   

Operating income

    71,044     49,856     64,891     2,273  
                   

Other income (expenses):

                         

Interest

    (26,595 )   (5,804 )   (9,951 )   (2,945 )

Other

    30     2     2     13  
                   

Total other expenses

    (26,565 )   (5,802 )   (9,949 )   (2,932 )
                   

Income (loss) before income taxes

    44,479     44,054     54,942     (659 )

Income tax provision

    6,805     1,546     1,928     470  
                   

Consolidated net income (loss)

    37,674     42,508     53,014     (1,129 )

Less: net income attributable to noncontrolling interest

    616              
                   

Net income (loss) attributable to stockholders

  $ 37,058   $ 42,508   $ 53,014   $ (1,129 )
                   

Net income (loss) per common share:

                         

Basic

  $ 0.53   $ 0.64   $ 0.80   $ (0.02 )

Diluted

  $ 0.53   $ 0.62   $ 0.78   $ (0.02 )

Weighted average common shares outstanding:

                         

Basic

    69,810     66,340     66,340     66,340  

Diluted

    71,666     68,196     68,196     66,340  

Consolidated Statements of Cash Flows Data:

                         

Cash provided by (used in):

                         

Operating activities

  $ 136,775   $ 62,754   $ 95,302   $ 18,872  

Investing activities

    (295,003 )   (186,900 )   (347,259 )   (465,475 )

Financing activities

    346,245     100,850     228,798     471,627  

Consolidated Balance Sheets Data:

                         

Cash and cash equivalents

  $ 196,888         $ 8,871   $ 32,030  

Total assets

    1,321,417           852,298     561,823  

Long-term debt

    500,000           362,000     170,000  

Total equity

    609,727           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 primarily 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 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 128,306 gross (101,723 net) acres at September 30, 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 September 30, 2013, we have operated up to eight vertical drilling rigs simultaneously and have drilled 293 gross operated vertical Wolfberry wells and one gross operated horizontal Wolfcamp well with a 99% success rate. This activity has allowed us to identify and de-risk our multi-year inventory of 4,890 gross (3,938 net) vertical drilling locations, while also identifying 1,047 gross (932 net) horizontal drilling locations in specific areas based on the geophysical and technical data, as of September 30, 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 12,960 BOE/D for the third quarter of 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.

Initial Public Offering

        On August 7, 2013, we completed our IPO of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $295.6 million, after deducting underwriting discounts and commissions and offering expenses. Upon closing of the IPO, the limited partnership agreement of

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Athlon Holdings LP was amended and restated to, among other things, modify Athlon Holdings LP's capital structure by replacing its different classes of interests with a single new class of units, the "New Holdings Units". The members of Holdings' management team and certain employees who held Class A limited partner interests now own New Holdings Units and entered into an exchange agreement under which (subject to the terms of the exchange agreement) they have the right to exchange their New Holdings Units for shares of our common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications. All other New Holdings Units are held by us. We used the net proceeds from the IPO (i) to reduce outstanding borrowings under our credit agreement, (ii) to provide additional liquidity for use in our drilling program and (iii) for general corporate purposes, including potential acquisitions.

Our Acquisition History

        A significant portion of our historical growth has been achieved through acquisitions.

        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 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 for accounting purposes. 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

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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 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 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.    We were formed on April 1, 2013. On April 26, 2013, Athlon Holdings LP underwent a corporate reorganization and as a result, Athlon Holdings LP became a majority-owned subsidiary of ours. We operate and control all of Athlon Holdings LP's business and affairs and consolidate its financial results. Please read "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.    We now 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

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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 results of operations for periods prior to the completion of our IPO.

        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 results of operations for periods prior to the reorganization transactions 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. At September 30, 2013, we operated seven vertical drilling rigs and one horizontal drilling rig. In the fourth quarter of 2013, we expanded to an eight-rig vertical drilling program and in 2014, we expect to add a second horizontal drilling rig. 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.

        Senior Notes.    In April 2013, Athlon Holdings LP issued $500 million in aggregate principal amount of 73/8% senior notes due 2021. We used the proceeds from the 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 resulted in higher interest expense in periods subsequent to April 2013 as compared to periods prior to April 2013. 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.

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        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:

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  

Oil

                         

NYMEX WTI High

  $ 110.53   $ 109.77   $ 109.77   $ 113.93  

NYMEX WTI Low

    86.68     77.69     77.69     75.67  

Differential to Average NYMEX WTI

    (3.74 )   (5.74 )   (6.29 )   (3.03 )

Natural Gas

                         

NYMEX Henry Hub High

    4.41     3.32     3.90     4.85  

NYMEX Henry Hub Low

    3.11     1.91     1.91     2.99  

Differential to Average NYMEX Henry Hub

    (0.25 )   (0.13 )   (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%); 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 primarily 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 reserves. 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. Since the completion of our IPO, G&A expense includes public company expenses as described above under "—Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations—Public Company Expenses."

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        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 exploratory projects that are not subject to current amortization. Interest expense also includes interest incurred under our senior notes.

        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 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 capital expenditures. Below are highlights of our financial and operating results for the first nine months of 2013:

    Our oil, natural gas and NGLs revenues increased 88% to $208.3 million in the first nine months of 2013 as compared to $111.1 million in the first nine months of 2012.

    Our average daily production volumes increased 75% to 11,378 BOE/D in the first nine months of 2013 as compared to 6,489 BOE/D in the first nine months of 2012. Oil and NGLs represented approximately 81% of our total production volumes in the first nine months of 2013.

    Our average realized oil price increased 4% to $94.43 per Bbl in the first nine months of 2013 as compared to $90.46 per Bbl in the first nine months of 2012. Our average realized natural gas price increased 39% to $3.42 per Mcf in the first nine months of 2013 as compared to $2.46 per Mcf in the first nine months of 2012. Our average realized NGL price decreased 13% to $30.87 per Bbl in the first nine months of 2013 as compared to $35.37 per Bbl in the first nine months of 2012.

    Our production margin increased 100% to $171.0 million in the first nine months of 2013 as compared to $85.6 million in the first nine months of 2012. Total wellhead revenues per BOE increased by 7% and total production expenses per BOE decreased by 16%. On a per BOE basis, our production margin increased 14% to $55.06 per BOE in the first nine months of 2013 as compared to $48.14 per BOE for the first nine months of 2012.

    We invested $315.2 million in oil and natural gas activities, of which $278.3 million was invested in development and exploration activities, yielding 125 gross (120 net) productive wells, and $36.9 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.

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        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, we expect the vertical wells we drill in 2013 through the Atoka formation in Howard, Midland & Other and Glasscock areas will 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 2013 is expected to average $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 drilled 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.

        In August 2013, we began drilling horizontal Wolfcamp wells on our acreage. Based on management's review of initial horizontal well results and decline curve analysis, we currently expect EURs for our horizontal Wolfcamp wells on the western side of the northern Midland Basin to average approximately 500 MBOE for a 5,000 foot lateral with an expected average drilling and completion cost of $6.9 million per well and 730 MBOE for a 7,500 foot lateral with an expected average drilling and completion cost of $8.5 million per well. We also expect EURs for our horizontal Wolfcamp wells on the eastern side of the northern Midland Basin to average approximately 625 MBOE for a 7,500 foot lateral with an expected average drilling and completion cost of $8.0 million per well. Assuming a benchmark crude oil price of $90 per Bbl and a natural gas price of $4.00 per Mcf, these wells are targeted to produce an average rate of return of 30%, 42% and 35%, respectively. Please read "Risk Factors—Risks Related to Our Business and the Oil and Gas Industry—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 preserved reserves."

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Results of Operations

    Comparison of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 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:

 
  Nine months ended
September 30,
  Increase /
(Decrease)
 
 
  2013   2012   $   %  

Revenues (in thousands):

                         

Oil

  $ 175,934   $ 91,407   $ 84,527     92 %

Natural gas

    11,894     5,323     6,571     123 %

NGLs

    20,508     14,379     6,129     43 %
                     

Total revenues

  $ 208,336   $ 111,109   $ 97,227     88 %
                     

Average realized prices:

                         

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

  $ 94.43   $ 90.46   $ 3.97     4 %

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

  $ 90.19   $ 88.00   $ 2.19     2 %

Natural gas ($/Mcf)

  $ 3.42   $ 2.46   $ 0.96     39 %

NGLs ($/Bbl)

  $ 30.87   $ 35.37   $ (4.50 )   -13 %

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

  $ 67.07   $ 62.49   $ 4.58     7 %

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

  $ 64.52   $ 61.09   $ 3.43     6 %

Total production volumes:

                         

Oil (MBbls)

    1,863     1,011     852     84 %

Natural gas (MMcf)

    3,474     2,165     1,309     60 %

NGLs (MBbls)

    664     407     257     63 %

Combined (MBOE)

    3,106     1,778     1,328     75 %

Average daily production volumes:

                         

Oil (Bbls/D)

    6,824     3,688     3,136     85 %

Natural gas (Mcf/D)

    12,725     7,903     4,822     61 %

NGLs (Bbls/D)

    2,433     1,484     949     64 %

Combined (BOE/D)

    11,378     6,489     4,889     75 %

        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.

 
  Nine months
ended
September 30,
 
 
  2013   2012  

Average realized oil price ($/Bbl)

  $ 94.43   $ 90.46  

Average NYMEX ($/Bbl)

  $ 98.17   $ 96.20  

Differential to NYMEX

  $ (3.74 ) $ (5.74 )

Average realized oil price to NYMEX percentage

    96 %   94 %

Average realized natural gas price ($/Mcf)

 
$

3.42
 
$

2.46
 

Average NYMEX ($/Mcf)

  $ 3.67   $ 2.59  

Differential to NYMEX

  $ (0.25 ) $ (0.13 )

Average realized natural gas price to NYMEX percentage

    93 %   95 %

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        Our average realized oil price as a percentage of the average NYMEX price improved to 96% for the first nine months of 2013 as compared to 94% for the first nine months of 2012, primarily due to the alleviation of certain capacity constraints between the Midland Basin, Cushing, Oklahoma and Gulf Coast refineries. Our average realized natural gas price as a percentage of the average NYMEX price remained relatively constant at 93% for the first nine months of 2013 as compared to 95% for the first nine months of 2012.

        Oil revenues increased 92% to $175.9 million in the first nine months of 2013 from $91.4 million in the first nine months of 2012 as a result of an increase in our oil production volumes of 852 MBbls and a $3.97 per Bbl decrease in our average realized oil price. Our higher oil production increased oil revenues by $77.1 million and was primarily the result of our development program in the Permian Basin. Our higher average realized oil price increased oil revenues by $7.4 million and was primarily due to a higher average NYMEX price, which increased to $98.17 per Bbl in the first nine months of 2013 from $96.20 per Bbl in the first nine months of 2012, and the narrowing of our oil differentials as previously discussed.

        Natural gas revenues increased 123% to $11.9 million in the first nine months of 2013 from $5.3 million in the first nine months of 2012 as a result of an increase in our natural gas production volumes of 1,309 MMcf and a $0.96 per Mcf increase in our average realized natural gas price. Our higher average realized natural gas price increased natural gas revenues by $3.3 million and was primarily due to a higher average NYMEX price, which increased to $3.67 per Mcf in the first nine months of 2013 from $2.59 per Mcf in the first nine months of 2012. Our higher natural gas production increased natural gas revenues by $3.2 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 (i) our well is not yet tied into the third-party gathering system, (ii) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported or (iii) our production is prorated due to high demand on the third-party gathering system. During the first nine months of 2013, we estimate that we flared approximately 3.4 MMcfe/D net, which included both residue gas and NGL production. We may flare additional gas from time to time.

        NGL revenues increased 43% to $20.5 million in the first nine months of 2013 from $14.4 million in the first nine months of 2012 as a result of an increase in our NGL production volumes of 257 MBbls, partially offset by a $4.50 per Bbl decrease in our average realized NGL price. Our higher NGL production increased NGL revenues by $9.1 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring as described above. Our lower average realized NGL price decreased NGL revenues by $3.0 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:

 
  Nine months ended
September 30,
  Increase / (Decrease)  
 
  2013   2012   $   %  

Expenses (in thousands):

                         

Production:

                         

Lease operating(a)

  $ 23,774   $ 17,846   $ 5,928     33 %

Production, severance and ad valorem taxes

    13,380     7,617     5,763     76 %

Processing, gathering and overhead

    169     55     114     207 %
                     

Total production expenses

    37,323     25,518     11,805     46 %

Other:

                         

Depletion, depreciation and amortization

    62,022     37,770     24,252     64 %

General and administrative

    13,723     7,212     6,511     90 %

Contract termination fee

    2,408         2,408     N/A  

Derivative fair value loss (gain)

    21,331     (9,590 )   30,921     -322 %

Accretion of discount on asset retirement obligations

    485     343     142     41 %
                     

Total operating

    137,292     61,253     76,039     124 %

Interest

    26,595     5,804     20,791     358 %

Income tax provision

    6,805     1,546     5,259     340 %
                     

Total expenses

  $ 170,692   $ 68,603   $ 102,089     149 %
                     

Expenses (per BOE):

                         

Production:

                         

Lease operating(a)

  $ 7.65   $ 10.04   $ (2.39 )   -24 %

Production, severance and ad valorem taxes

    4.31     4.27     0.04     1 %

Processing, gathering and overhead

    0.05     0.03     0.02     67 %
                     

Total production expenses

    12.01     14.34     (2.33 )   -16 %

Other:

                         

Depletion, depreciation and amortization

    19.97     21.24     (1.27 )   -6 %

General and administrative

    4.42     4.06     0.36     9 %

Contract termination fee

    0.78         0.78     N/A  

Derivative fair value loss (gain)

    6.87     (5.39 )   12.26     -227 %

Accretion of discount on asset retirement obligations

    0.16     0.19     (0.03 )   -16 %
                     

Total operating

    44.21     34.44     9.77     28 %

Interest

    8.56     3.26     5.30     163 %

Income tax provision

    2.19     0.87     1.32     152 %
                     

Total expenses

  $ 54.96   $ 38.57   $ 16.39     42 %
                     

(a)
Includes non-cash equity-based compensation of $203,000 ($0.07 per BOE) and $21,000 ($0.01 per BOE) for the nine months ended September 30, 2013 and 2012, respectively.

        Production expenses.    Production expenses attributable to LOE increased 33% to $23.8 million in the first nine months of 2013 from $17.8 million in the first nine months of 2012 as a result of an increase in production volumes from wells drilled, which contributed $13.3 million of additional LOE, partially offset by a $2.39 decrease in the average per BOE rate, which would have reduced LOE by $7.4 million if production had been unchanged. The decrease in our average LOE per BOE rate was attributable to wells we successfully drilled and completed in 2013 where we are experiencing economies of scale from our drilling program and from savings achieved through 2012 infrastructure

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projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of saltwater.

        Production expenses attributable to production, severance and ad valorem taxes increased 76% to $13.4 million in the first nine months of 2013 from $7.6 million in the first nine months of 2012 primarily due to higher wellhead revenues resulting from increased production from our drilling activity. As a percentage of wellhead revenues, production, severance and ad valorem taxes decreased to 6.4% in the first nine months of 2013 as compared to 6.9% in the first nine months of 2012 primarily related to ad valorem taxes due to an increase in the number of wells brought on production in the first nine months of 2013 as compared to the first nine months of 2012 as we continue to utilize more efficient drilling rigs, reducing our time from spud to rig release.

        DD&A expense.    DD&A expense increased 64% to $62.0 million in the first nine months of 2013 from $37.8 million in the first nine months of 2012 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.

        G&A expense.    G&A expense increased 90% to $13.7 million in the first nine months of 2013 from $7.2 million in the first nine months of 2012 primarily due to (i) $1.1 million of bonuses paid subsequent to the successful completion of our IPO, (ii) $1.0 million of non-cash equity-based compensation related to the accelerated vesting of the Class B limited partner interests in Athlon Holdings LP as a result of the IPO, (iii) nonrecurring corporate reorganization costs related to the transition from a partnership to a corporation of $0.7 million and (iv) higher payroll and payroll-related costs as we continue to add employees in order to manage our growing asset base.

        Contract termination fee.    Athlon Holdings LP was a party to a Services Agreement, dated August 23, 2010, which required Athlon Holdings LP to compensate Apollo for consulting and advisory services. Upon the consummation of our IPO, Athlon Holdings LP terminated the Services Agreement and, in connection with the termination, Athlon Holdings LP paid $2.4 million to Apollo. Such payment corresponded to the present value as of the date of termination of the aggregate annual fees that would have been payable during the remainder of the term of the Services Agreement (assuming a term ending on August 23, 2020).

        Derivative fair value loss (gain).    During the first nine months of 2013, we recorded a $21.3 million derivative fair value loss as compared to a $9.6 million derivative fair value gain in the first nine months of 2012. Since we do not use hedge accounting, changes in fair value of our derivatives are recognized as gains and losses in the current period. Included in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums during the first nine months of 2013 of $7.9 million as compared to $2.5 million during the first nine months of 2012.

        Interest expense.    Interest expense increased to $26.6 million in the first nine months of 2013 from $5.8 million in the first nine months of 2012 due to higher long-term debt balances and higher borrowing costs in the first nine months of 2013 when compared to the first nine months of 2012. Our weighted-average total debt was $481.1 million for the first nine months of 2013 as compared to $208.4 million for the first nine months of 2012. This increase in total debt was due to (i) funding requirements to develop our oil and natural gas properties that are not covered by our operating cash flows and (ii) a $75 million distribution to Athlon Holdings LP's Class A limited partners in April 2013. Also, as a result of the issuance of our senior notes, our former second lien term loan was paid off and retired and the borrowing base of our credit agreement was reduced resulting in a write off of unamortized debt issuance costs of approximately $2.8 million to interest expense.

        Our weighted-average interest rate increased to 7.3% for the first nine months of 2013 as compared to 3.7% for the first nine months of 2012. This increase in borrowing cost is primarily due to the issuance of our senior notes, a portion of the net proceeds from which were used to substantially pay down outstanding borrowings on our credit agreement that were subject to lower interest rates than

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borrowings on our senior notes. Our weighted-average interest expense for the first nine months of 2013 includes the impact of the write off of unamortized debt issuance costs and is expected to decline in future periods as we are not anticipating a need for a similar write off and as borrowings on the credit agreement increase relative to our senior notes resulting in a lower average interest rate.

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

 
  Nine months ended
September 30,
   
 
 
  Increase /
(Decrease)
 
 
  2013   2012  
 
  (in thousands)
 

Credit agreement

  $ 3,027   $ 4,613   $ (1,586 )

Senior notes

    16,854         16,854  

Former second lien term loan

    2,777     679     2,098  

Write off of debt issuance costs

    2,838     57     2,781  

Amortization of debt issuance costs

    1,280     455     825  

Less: interest capitalized

    (181 )       (181 )
               

Total

  $ 26,595   $ 5,804   $ 20,791  
               

        Income taxes.    In the first nine months of 2013, we recorded an income tax provision of $6.8 million as compared to $1.5 million in the first nine months 2012. In the first nine months of 2013, we had income before income taxes and noncontrolling interest of $44.5 million as compared to $44.1 million in the first nine months of 2012. Our effective tax rate increased to 15.3% in the first nine months of 2013 as compared to 3.5% in the first nine months of 2012 as a result of our corporate reorganization on April 26, 2013 in which Athlon Energy Inc. (a C-corporation) obtained most of the interests in Athlon Holdings LP. Prior to April 26, 2013, Athlon Holdings LP, our accounting predecessor, was a limited partnership not subject to federal income taxes.

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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) (before 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) (before 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 WTI ($/Bbl)

    94.19     95.11  

Differential to NYMEX WTI

    (6.29 )   (3.03 )

Average realized oil price to NYMEX WTI percentage

    93 %   97 %

Average realized natural gas price ($/Mcf)

 
$

2.66
 
$

3.46
 

Average NYMEX Henry Hub ($/Mcf)

    2.79     4.00  

Differential to NYMEX Henry Hub

    (0.13 )   (0.54 )

Average realized natural gas price to NYMEX Henry Hub percentage

    95 %   87 %

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        Our average realized oil price as a percentage of the average NYMEX WTI 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 implemented and several more are underway to ease these transportation difficulties which we believe could reduce our differentials in the future. Our average realized natural gas price as a percentage of the average NYMEX Henry Hub 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 WTI 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 Henry Hub 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(a)

  $ 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 of discount on asset retirement obligations

    478     344     134     39 %
                     

Total operating

    92,220     63,408     28,812     45 %

Interest

    9,951     2,945     7,006     238 %

Income tax provision

    1,928     470     1,458     310 %
                     

Total expenses

  $ 104,099   $ 66,823   $ 37,276     56 %
                     

Expenses (per BOE):

                         

Production:

                         

Lease operating(a)

  $ 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 of discount on asset retirement obligations

    0.19     0.36     (0.17 )   -47 %
                     

Total operating

    35.76     65.76     (30.00 )   -46 %

Interest

    3.86     3.05     0.81     27 %

Income tax provision

    0.75     0.49     0.26     53 %
                     

Total expenses

  $ 40.37   $ 69.30   $ (28.93 )   -42 %
                     

(a)
Includes non-cash equity-based compensation of $29,000 ($0.01 per BOE) for 2012.

        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.

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        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 revenues 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 were party to a Transaction Fee Agreement, dated August 23, 2010, which required 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 agreement

  $ 5,932   $ 2,387   $ 3,545  

Former second lien term loan

    3,081         3,081  

Write off of debt issuance costs

    444         444  

Amortization of debt issuance costs and deferred premiums

    713     558     155  

Less: interest capitalized

    (219 )       (219 )
               

Total

  $ 9,951   $ 2,945   $ 7,006  
               

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:

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Development(1)

  $ 132,883   $ 132,917   $ 201,174   $ 71,403  

Exploration(2)

    145,435     55,859     75,008     17,829  
                   

Total

  $ 278,318   $ 188,776   $ 276,182   $ 89,232  
                   

(1)
Includes asset retirement obligations incurred of $426,000 and $407,000 during the nine months ended September 30, 2013 and 2012, respectively, and $606,000 and $108,000 during the years ended December 31, 2012 and 2011, respectively.

(2)
Includes asset retirement obligations incurred of $311,000 and $147,000 during the nine months ended September 30, 2013 and 2012, respectively, and $209,000 and $58,000 during years ended December 31, 2012 and 2011, respectively.

        Our development capital primarily relates to drilling development and infill wells, workovers of existing wells and field related facilities. Our development capital for the first nine months of 2013 yielded 51 gross (50 net) productive wells and no dry holes. Our development capital for 2012 yielded 102 gross (94 net) productive wells and two gross (two net) dry holes.

        Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals and geological and geophysical costs. Our exploration capital for first nine months of 2013 yielded 74 gross (70 net) productive wells and no dry holes. Our exploration capital for 2012 yielded 29 gross (28 net) productive wells and no dry holes.

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        The level of our development and exploration activities continues to increase primarily due to (i) our utilization of 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 period, and (ii) our higher rig count, including our first horizontal drilling rig which was added in the third quarter of 2013.

        In 2013, we expect our drilling capital expenditures to be $380 million to $390 million, plus an additional $15 million for leasing, infrastructure and capital workovers, and to drill 169 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells.

        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:

 
  Nine months ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Acquisitions of proved properties(1)

  $ 5,883   $ 3,126   $ 42,122   $ 287,400  

Acquisitions of unproved proerpties

    30,985     532     38,908     130,273  
                   

Total

  $ 36,868   $ 3,658   $ 81,030   $ 417,673  
                   

(1)
Includes asset retirement obligations incurred of $335,000 during the nine months ended September 30, 2013 and $60,000, and $3.3 million during the years ended December 31, 2012 and 2011, respectively.

        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 September 30, 2013 and December 31, 2012, our working capital (defined as total current assets less total current liabilities) was a $108.6 million surplus and a $22.2 million deficit, respectively. Since our principal source of operating cash flows comes from oil and natural gas reserves to be produced in future periods, which cannot be reported as working capital, we often have negative working capital. We expect to continue to have a working capital surplus unless significant acquisition opportunities present themselves. We expect our cash flows from operating activities and availability under our credit agreement 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 September 30, 2013:

 
  Payments Due by Period  
Contractual Obligations and Commitments
  Total   Three Months
Ending
December 31,
2013
  Years Ending
December 31,
2014 - 2015
  Years Ending
December 31,
2016 - 2017
  Thereafter  
 
  (in thousands)
 

Credit agreement(1)

  $   $   $   $   $  

Senior notes(1)

    795,000     18,437     73,750     73,750     629,063  

Commodity derivative contracts(2)

    9,966     4,536     5,430          

Development commitments(3)

    60,092     60,092              

Operating leases and commitments(4)

    1,433     117     938     378      

Asset retirement obligations(5)

    39,275     60             39,215  
                       

Total

  $ 905,766   $ 83,242   $ 80,118   $ 74,128   $ 668,278  
                       

(1)
Includes principal and projected interest payments. As of September 30, 2013, there were no outstanding borrowings under our credit agreement. Please read "—Liquidity" for additional information regarding our long-term debt.

(2)
Represents net liabilities for our commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read "—Quantitative and Qualitative Disclosures about Market Risk" for additional information regarding our commodity derivative contracts.

(3)
Represents authorized purchases for work in process related to our drilling activities.

(4)
Represents operating leases that have non-cancelable lease terms in excess of one year.

(5)
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.

        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:

 
  Nine months ended
September 30,
  Year ended December 31,  
 
  2013   2012   2012   2011  
 
  (in thousands)
 

Net cash provided by operating activities

  $ 136,775   $ 62,754   $ 95,302   $ 18,872  

Net cash used in investing activities

    (295,003 )   (186,900 )   (347,259 )   (465,475 )

Net cash provided by financing activities

    346,245     100,850     228,798     471,627  
                   

Net increase (decrease) in cash

  $ 188,017   $ (23,296 ) $ (23,159 ) $ 25,024  
                   

        Cash flows from operating activities.    Cash provided by operating activities increased $74.0 million to $136.8 million in the first nine months of 2013 from $62.8 million in the first nine months of 2012,

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primarily due to an increase in our production margin due to a 75% increase in our total production volumes as a result of wells drilled, partially offset by increased expenses as a result of having more producing wells in the first nine months of 2013 as compared to the first nine months 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 $108.1 million to $295.0 million in the first nine months of 2013 from $186.9 million in the first nine months of 2012, primarily due to a $74.7 million increase in amounts paid to develop oil and natural gas properties and a $33.2 million increase in leasehold acquisition costs. The increase in our development expenditures was primarily due to (i) our utilization of 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, and (ii) our higher rig count, including our first horizontal drilling rig which was added in the third quarter of 2013.

        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 have historically consisted of net proceeds from and payments on long-term debt and contributions from partners. We periodically draw on our credit agreement to fund acquisitions and other capital commitments.

        During the first nine months of 2013, we received net cash of $346.2 million from financing activities, including $296.0 million of net proceeds from our IPO and $487.1 million of net proceeds from the issuance of our senior notes, partially offset by $125 million used to repay in full and terminate our former second lien term loan, net repayments of $237 million under our credit agreement and a $75 million distribution to Athlon Holdings LP's Class A limited partners. Net repayments reduced the outstanding borrowings under our credit agreement from $237 million at December 31, 2012 to none at September 30, 2013.

        During the first nine months of 2012, we received net cash of $100.9 million from financing activities, including $122.9 million of net proceeds from the issuance of our former second lien term loan, partially offset by net repayments of $21.5 million 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.

        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 to Athlon Holdings LP, including from 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

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equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our cash on hand, internally generated cash flows and expected future availability under our credit agreement 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 expect our drilling capital expenditures to be $380 million to $390 million, plus an additional $15 million for leasing, infrastructure and capital workovers. 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 NGL prices. During the first nine months of 2013, our average realized oil and natural gas prices increased by 4% and 39%, respectively, as compared to the first nine months of 2012, while our average realized NGL price decreased by 13%. During 2012, our average realized oil, natural gas and NGL 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 September 30, 2013, our hedged oil volumes for the fourth quarter of 2013, 2014 and 2015 represent 89%, 101% and 16%, respectively, of our third quarter 2013 oil production at weighted average prices of $95.01, $92.67 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.

        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 and our IPO 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 September 30, 2013, the borrowing base was

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$320 million and there were no outstanding borrowings and no outstanding letters of credit under our credit agreement. In November 2013, we amended our credit agreement to, among other things, increase the borrowing base to $525 million. As of January 24, 2014, there were no outstanding borrowings under our credit agreement. 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 %   1.50 %   0.50 %

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

    0.375 %   1.75 %   0.75 %

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

    0.50 %   2.00 %   1.00 %

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

    0.50 %   2.25 %   1.25 %

Greater than .90 to 1

    0.50 %   2.50 %   1.50 %

        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.

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        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 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.

        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. On August 14, 2013, Athlon Holdings LP entered into a supplemental indenture pursuant to which we became an unconditional guarantor of the senior notes.

        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 September 30, 2013, we had total assets of $1.3 billion and total capitalization of $1.1 billion, of which 55% was represented by equity and 45% 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:

 
  Nine months
ended
September 30,
  Year ended
December 31,
 
 
  2013   2012   2012   2011  

Average realized prices:

                         

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

  $ 94.43   $ 90.46   $ 87.90   $ 92.08  

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

    90.19     88.00     87.16     87.16  

Natural gas ($/Mcf)

    3.42     2.46     2.66     3.46  

NGLs ($/Bbl)

    30.87     35.37     34.65     45.96  

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

    67.07     62.49     60.91     68.13  

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

    64.52     61.09     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

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    judgment of the independent reserve engineer.

        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

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activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense.

    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

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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.

    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. All commodity derivative contracts we have entered into are 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.

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For commodity derivative contracts which are in a liability position, we use the yield on our senior notes less the risk-free rate.

    Income Taxes

        We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax laws and rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

        We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets, including net operating losses. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends and our outlook for future years. We believe it is more likely than not that certain net operating losses can be carried forward and utilized.

        In April 2013, we effected a corporate reorganization. Athlon Holdings LP, our accounting predecessor, is a partnership structure not subject to federal income tax. Pursuant to the corporate reorganization, the Apollo Funds' Class A limited partner interests and the Class B limited partner interests of Athlon Holdings LP were exchanged for shares of our common stock. Our operations are now subject to federal income tax. The tax implications of the corporate reorganization and the tax impact of the conversion to operating as a taxable entity have been reflected in our consolidated financial statements.

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 of an entity's rights of offset 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

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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 September 30, 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, or one of their affiliates:

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

BNP Paribas

  $ 458  

        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.

        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 and collars. Swaps provide a fixed price for a notional amount of sales volumes. 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.

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        The following table summarizes our open commodity derivative contracts as of September 30, 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)
 

Oct. - Dec. 2013

    150   $ 75.00     150   $ 105.95     7,000   $ 95.01   $ (4,205 )

2014

                    7,950     92.67     (7,532 )

2015

                    1,300     93.18     2,101  
                                           

                                      $ (9,636 )
                                           

        We are also a party to Midland-Cushing basis differential swaps for 5,000 Bbls/D at $1.20/Bbl for October through December 2013. At September 30, 2013, the fair value of these contracts was a liability of approximately $0.3 million.

        As of September 30, 2013, the fair market value of our oil derivative contracts was a net liability of $10.0 million. Based on our open commodity derivative positions at September 30, 2013, a 10% increase in NYMEX prices for oil would increase our net commodity derivative liability by approximately $37.2 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 $27.2 million.

    Interest rate sensitivity

        At September 30, 2013, we had outstanding debt of $500 million, all of which bears interest at a fixed rate of 73/8%. At September 30, 2013, the fair value of our senior notes was approximately $515.6 million.

Internal Controls and Procedures

        In accordance with the Securities Exchange Act of 1934 (the "Exchange Act") Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2013 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

        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. However, we are required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of its internal control over financial reporting. We will not be required to make our first assessment of 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 primarily 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 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 128,306 gross (101,723 net) acres at September 30, 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 September 30, 2013, we have operated up to eight vertical drilling rigs simultaneously and have drilled 293 gross operated vertical Wolfberry wells and one gross operated horizontal Wolfcamp well with a 99% success rate. This activity has allowed us to identify and de-risk our multi-year inventory of 4,890 gross (3,938 net) vertical drilling locations, while also identifying 1,047 gross (932 net) horizontal drilling locations in specific areas based on the geophysical and technical data, as of September 30, 2013. 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 vertical drilling locations by primary geographic area as of September 30, 2013:

 
   
   
  Identified Vertical Drilling Locations(1)  
 
  Acreage  
 
  Net
40-acre(2)
  Net
20-acre
   
  Drilling
Inventory(3)
(years)
 
 
  Gross   Net   Net Total  

Howard

    74,128     54,902     1,163     1,353     2,516     35  

Midland & Other

    36,573     33,709     388     411     799     19  

Glasscock

    17,605     13,112     261     362     623     27  
                             

Total

    128,306     101,723     1,812     2,126     3,938     29  
                             

(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.

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        In addition, we have identified 1,047 gross (932 net) horizontal drilling locations targeting Wolfcamp A, Wolfcamp B, Wolfcamp C and Cline intervals, which comprise 320 gross (285 net), 361 gross (325 net), 135 gross (126 net) and 231 gross (196 net) locations, respectively. This represents a drilling inventory of 44 years based on a two-rig horizontal drilling program.

        Since our inception, we have completed two significant acquisitions. At the time of each acquisition, based on internal engineering estimates, these properties collectively contributed approximately 3,000 BOE/D of production and approximately 35.5 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 September 30, 2013, we have drilled 293 gross operated vertical Wolfberry wells and one gross operated horizontal Wolfcamp well with a 99% success rate and grown our production to 12,960 BOE/D for the third quarter of 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 expect our drilling capital expenditures to be $380 million to $390 million, plus an additional $15 million for leasing, infrastructure and capital workovers, and to drill 169 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells. We currently operate eight vertical drilling rigs and one horizontal drilling rig. In 2014, we intend to expand to a two-rig horizontal drilling program.

        Our estimate of proved reserves is prepared by 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 information regarding our proved reserves as of December 31, 2012:

 
  Estimated Total Proved Reserves  
 
  Oil
(MMBbls)
  NGLs
(MMBbls)
  Natural
Gas
(Bcf)
  Total
(MMBOE)
  % Liquids(1)   PV-10(2)
(in millions)
 

Howard

    20.2     7.3     36.3     33.5     82 % $ 365.4  

Midland & Other

    17.6     8.3     44.7     33.3     78 %   337.0  

Glasscock

    11.6     3.7     22.7     19.2     80 %   164.2  
                      &n