The selling stockholders are offering 14,000,000 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 closing price of our common stock on February 6, 2014 was $32.78 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 2,100,000 shares of common stock 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 2,100,000 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.

The underwriters expect to deliver the shares to purchasers on or about February 12, 2014 through the book-entry facilities of The Depository Trust Company.

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.

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.

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.

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

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.
•: 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

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.

•: 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 ("IPO") 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.

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

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."

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.

(1): The Apollo Funds and the public stockholders will hold 46.0% and 41.6% 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 February 6, 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.

Upon completion of this public offering, the Apollo Funds will beneficially own approximately 48.5% of our common stock (or approximately 46.0% 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.

THE OFFERING


Common stock offered by the selling stockholders		14,000,000 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).
Option to purchase additional shares		The underwriters have a 30-day option to purchase 2,100,000 shares of common stock from the selling stockholders.
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)."

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.

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."

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.

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.

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.

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.

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

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

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.

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:

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

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:

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

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

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

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:

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

require us to borrow to fund our current or future capital budgets. Lower oil, natural gas and NGL prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. Substantial decreases in oil, natural gas and NGL prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. As a result, a substantial or extended decline in oil, natural gas or NGL prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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

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

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.

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

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

You should not assume that the Standardized Measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2012 and 2011, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural

gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

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

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 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:

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

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for

petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

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

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

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 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.

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:

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 February 4, 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.

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.

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.

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

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

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.

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

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

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 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

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.

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.

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.

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 48.5% of the combined voting power of our common stock (or approximately 46.0% 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

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.

Following this offering, 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 will 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, our Compensation Committee and Nominating and Corporate Governance Committee must be composed entirely of "independent directors" (as defined by the NYSE rules), and a majority of the directors on our board must be independent. Our board of directors currently consists of seven directors. 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.

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:

As a result, the Apollo Funds or their affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to the Apollo Funds and their affiliates could adversely

impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read "Description of Capital Stock."

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

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies, as described under the caption "Certain Relationships and Related Party Transactions." The resolution of any conflicts that may arise in connection with any related party transactions that we have entered into with the Apollo Funds or their affiliates, including pricing, duration or other terms of service, may not always be in our or our stockholders' best interests because the Apollo Funds may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, please read "—Our largest stockholder controls a significant percentage of our common stock, and their interests may conflict with those of our other stockholders."

We 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:

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 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:

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.

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.

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:

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.

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.

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.

On February 6, 2014, the closing price of our common stock was $32.78 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.

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.

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

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

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.

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.

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

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.

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.

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

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:

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

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.

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

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

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.

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."

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.

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:

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

We measure the expected return of our wells based on EUR and the related costs of acquisition, development and production. Based on estimates prepared by our independent reserve engineers, as of December 31, 2012, 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."

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.

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.

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	%

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

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

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:

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.

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	%

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.

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	%

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

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

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

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:

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.

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.

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:

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.

Contractual obligations. The following table provides our contractual obligations and commitments as of September 30, 2013:

(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.

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,

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.

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

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

$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 February 4, 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:

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:

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:

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.

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:

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.

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.

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:

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.

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

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

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

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

We capitalize interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that

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

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.

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

Inherent to the present-value calculation are numerous estimates, assumptions and judgments, including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions affect the present value of the

abandonment liability, we make corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. These revisions result in prospective changes to DD&A expense and accretion of the discounted abandonment liability.

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.

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.

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

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.

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.

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.

The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This

information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

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.

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:

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 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.

The following table summarizes our open commodity derivative contracts as of September 30, 2013:

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.

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.

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.

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:

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.

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:

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

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.

	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	%

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 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).

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 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.

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

A significant portion of our historical growth has been achieved through acquisitions. Since our formation in August 2010, we have completed two significant acquisitions that have given us a unique and highly attractive acreage positions, underpinned by strong baseline production and proved reserves.

We acquired certain oil and natural gas properties and related assets in the Permian Basin from Element Petroleum, LP in October 2011 for $253.2 million in cash. 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. We acquired certain oil and natural gas properties and related assets in the Permian Basin from SandRidge Exploration and Production, LLC in January 2011 for $156.0 million in cash. 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. As a result of these acquisitions and our continued operations, the PV-10 of our proved reserves totaled approximately $866.6 million as of December 31, 2012.

The Permian Basin, which includes the Delaware Basin, the Central Basin Platform and the Midland Basin, is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential. Based on data from the Texas Railroad Commission and the New Mexico Oil Conservation Division, current total production from the Permian Basin is approximately 2.2 MMBOE/D, of which 61% is oil. As of November 2013, there were 462 total rigs operating in the Permian Basin, making it the most active basin in the United States. According to a report by the Energy Information Administration in August 2013, the Permian Basin is the largest oil producing basin in the United States and contains approximately 22% of the oil reserves in the United States. These reserves are found in multiple proven oil and liquids-rich natural gas producing stratigraphic horizons, which we refer to as stacked pay zones. These multiple stacked pay zones can accommodate multiple completions in a single wellbore with the potential for both vertical and horizontal drilling.

Our properties are located within the Midland Basin in areas with approximately 3,000 feet to 4,000 feet of stacked pay zones. Our vertical drilling program is targeting the Spraberry, Wolfcamp, Cline, Strawn, Atoka and Mississippian formations. As we continue to develop our inventory of identified vertical drilling locations, we expect to significantly expand our horizontal inventory based upon the information we learn about the formations underlying our leaseholds. In 2012, drilling activity in the Midland Basin continued to show a trend toward horizontal development. Based on data from the Texas Railroad Commission, of the 3,555 wells drilled in the Midland Basin in 2012, 18% were horizontal compared to 10% in 2011. A significant portion of the vertical drilling activity in the Midland Basin targets the Wolfberry Play due to the low-risk nature of the resources available in the

play. Companies currently active in the Midland Basin include Apache Corporation, Pioneer Natural Resources Company, EOG Resources, Inc., Concho Resources Inc., Energen Corporation and Laredo Petroleum Holdings, Inc.

Howard. As of September 30, 2013, we had 74,128 gross (54,902 net) acres and an inventory of 1,560 gross (1,163 net) identified vertical drilling locations on 40-acre spacing and an additional 1,762 gross (1,353 net) identified vertical drilling locations on 20-acre spacing. We are currently operating four vertical drilling rigs in this area and we have drilled 148 gross (139 net) operated vertical wells from the time we began operations in January 2011 through September 30, 2013.

Midland & Other. As of September 30, 2013, we had 36,573 gross (33,709 net) acres and an inventory of 419 gross (388 net) identified vertical drilling locations on 40-acre spacing and an additional 460 gross (411 net) identified vertical drilling locations on 20-acre spacing. We are currently operating three vertical drilling rigs in this area and we have drilled 84 gross (84 net) operated vertical wells from the time we began operations in January 2011 through September 30, 2013.

Glasscock. As of September 30, 2013, we had 17,605 gross (13,112) net acres and an inventory of 289 gross (261 net) identified vertical drilling locations on 40-acre spacing and an additional 400 gross (362 net) identified vertical drilling locations on 20-acre spacing. We are currently operating one vertical drilling rig in this area and we have drilled 61 gross (59 net) operated vertical wells from the time we began operations in January 2011 through September 30, 2013.

Horizontal Wells. As of September 30, 2013, we have identified 1,047 gross (932 net) horizontal drilling locations consisting of 320 gross (285 net) Wolfcamp A locations, 361 gross (325 net) Wolfcamp B locations, 135 gross (126 net) Wolfcamp C locations and 231 gross (196 net) Cline locations. We added our first horizontal rig in the third quarter of 2013 and we drilled one gross (one net) well through September 30, 2013.

Facilities. Our oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include field gathering systems, storage tank batteries, saltwater disposal systems, oil/gas/water separation equipment and pumping units. We own four saltwater disposal systems in our Howard County core areas with over 22,000 barrels of water per day ("bwpd") capacity and access to over 74 fresh water supply wells throughout our acreage, a saltwater disposal system in our Glasscock County core area with over 2,700 bwpd capacity and access to over 32 fresh water supply wells throughout our acreage, and five saltwater disposal systems in our Midland County core areas with over 21,000 bwpd capacity and access to over 38 fresh water supply wells throughout our acreage. In addition, we have established pipeline infrastructures in each of these core areas to reduce our need for trucking services.

Recent Activity. During 2012, we drilled 133 gross (124 net) wells and our 2012 development capital was approximately $276 million. For 2012, our F&D costs were $8.42 per BOE. During 2011, we drilled 24 gross (21 net) wells. As of September 30, 2013, we had 2,268 identified gross potential vertical drilling locations based on 40-acre spacing and an additional 2,622 identified gross potential vertical drilling locations based on 20-acre spacing. The vertical wells are expected to be drilled to approximately 9,600 feet to 12,250 feet at an estimated average completed gross well cost of approximately $1.80 million to $2.15 million per well. In this prospectus, we define identified potential drilling locations as locations specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data on 40-acre or 20-acre spacing as indicated. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Evaluation and Review of Proved Reserves. Our historical proved reserve estimates were prepared by CG&A, our independent petroleum engineers. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The third-party engineering firm does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Copies of the independent petroleum engineering firm's proved reserve report as of December 31, 2012 is attached hereto as an exhibit.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Jennifer Palko, our Vice President—Business Development and Engineering, is primarily responsible for overseeing the preparation of all of our reserve estimates. Ms. Palko is a petroleum engineer with over 19 years of reservoir and operations experience and our geoscience staff has an average of approximately 14 years of industry experience per person.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

Estimation of Proved Reserves. Under SEC rules, proved reserves are those 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 and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2012 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall

into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

To estimate economically recoverable proved reserves and related future net cash flows, CG&A considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Oil and Natural Gas Reserves. The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2012 and 2011, based on the proved reserve reports prepared by CG&A, an independent petroleum engineering firm, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States. Copies of the proved reserve reports as of December 31, 2012 and 2011 prepared by CG&A with respect to our proved reserves are included as exhibits to the registration

statement of which this prospectus forms a part. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC.

	December 31,

	2012		2011
Proved developed reserves:
Oil (MBbls)		14,470		7,942
Natural gas (MMcf)		31,965		14,063
NGLs (MBbls)		5,900		3,211
Combined (MBOE)		25,698		13,496
Proved undeveloped reserves:
Oil (MBbls)		34,953		18,030
Natural gas (MMcf)		71,718		37,497
NGLs (MBbls)		13,375		8,338
Combined (MBOE)		60,281		32,618
Proved reserves:
Oil (MBbls)		49,423		25,972
Natural gas (MMcf)		103,683		51,560
NGLs (MBbls)		19,275		11,549
Combined (MBOE)		85,979		46,114

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read "Risk Factors" appearing elsewhere in this prospectus.

Additional information regarding our proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this prospectus and the proved reserve reports as of December 31, 2012 and 2011 which are included as exhibits to the registration statement of which this prospectus forms a part.

As of December 31, 2012, our proved undeveloped reserves were composed of 34,953 MBbls of oil, 71,718 MMcf of natural gas and 13,375 MBbls of NGLs, for a total of 60,281 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Costs incurred relating to the development of PUDs reflected in our 2011 proved reserve report were $135.3 million during 2012. In addition, we incurred costs of $65.9 million to develop locations that became classified as PUDs during 2012. Estimated future development costs relating to the development of PUDs are projected to be approximately $103.0 million in 2013, $163.2 million in 2014, $174.1 million in 2015, $315.9 million in 2016 and $289.7 million in 2017. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years. All of our PUD drilling locations are scheduled to be drilled prior to the end of 2017.

As of December 31, 2012, approximately 4% of our total proved reserves were classified as proved developed non-producing.

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for the periods indicated:

	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

As of December 31, 2012, we owned an average 92% working interest in 492 gross (454 net) productive wells. Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

The following table sets forth information as of September 30, 2013 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells and does not include undrilled held by production acreage under the terms of the lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is

the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the expiration dates of our leases on undeveloped acres as of September 30, 2013:

We have not attributed any PUD reserves to acreage whose expiration date precedes the scheduled date for PUD drilling.

The following table sets forth information with respect to the number of wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells

drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

As of December 31, 2012, we had 25 gross (23 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table.

As of December 31, 2012, we operated approximately 99% of our proved reserves. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

We market all of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market price under contracts with terms ranging from month-to-month to over five years. All of our oil is also sold under various contracts with a month-to-month term.

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For 2012, three purchasers accounted for more than 10% of our revenues: Pecos Gathering & Marketing (43%); Occidental Petroleum Corporation (29%); and DCP Midstream (12%). For 2011, three purchasers accounted for more than 10% of our revenues: Occidental Petroleum Corporation (58%); DCP Midstream (13%); and Pecos Gathering & Marketing (13%). If a major customer decided to stop purchasing oil and natural gas from us, 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 major purchasers 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.

During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck or pipeline to a tank farm, another pipeline or a refinery. Our natural gas is transported from the wellhead to the purchaser's meter and pipeline interconnection point through our gathering system.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. 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 productive oil and natural gas properties and exploratory prospects or to 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 or more integrated 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.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our properties and believe that we have satisfactory title to our properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 30%, resulting in a net revenue interest to us of 70% to 80%.

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our results of operations and financial condition, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, as amended, ("RCRA") and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute "solid wastes" that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as "hazardous wastes." Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, ("CERCLA") also known as the "Superfund" law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed "responsible parties" may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such "hazardous substances" have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the "CWA"), the SDWA, the Oil Pollution Act (the "OPA") and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Noncompliance with the CWA or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The CAA and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA approved final regulations under the CAA that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail in "—Regulation of Hydraulic Fracturing." These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. 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 January 2011. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it also became effective 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 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 greenhouse gas 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 that correspond to 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 such allowances is expected to escalate significantly.

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 SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as "Class II" UIC wells. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. The EPA issued a Progress Report in December 2012 and a final draft is anticipated in 2014 for peer review and public comment. A committee of the U.S. House of Representatives is also conducting 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. Further, 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. 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.

On August 16, 2012, the EPA published final regulations under 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 VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final 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.

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. In June 2011, Texas enacted a law requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that will apply to all wells for which the Texas Railroad Commission issues an initial drilling permit on or after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the 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.

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or

the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and NGLs are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in "first sales," which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural

gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation. Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment

opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We have insurance policies for property (including leased oil and natural gas properties), general liability, operational control of certain wells, pollution, commercial auto, umbrella liability, inland marine, workers' compensation and other coverage. The limits for certain of our policies are as follows:

As noted above, most of our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. 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. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider.

As of December 31, 2013, we had 70 full-time employees, including four geologists, 13 engineers and 10 land professionals. Of these full-time employees, 51 are salaried administrative or supervisory

employees and 38 work in our corporate headquarters. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full-time employees. We consider our relations with our employees to be satisfactory.

Our corporate headquarters is located in Fort Worth, Texas. We also lease additional office space in Midland, Texas. We believe that our facilities are adequate for our current operations.

From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers' compensation claims and employment related disputes. We do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

Name	Age	Position with Athlon

Robert C. Reeves	44	President, Chief Executive Officer and Director
Nelson K. Treadway	48	Senior Vice President—Business Development and Land
William B. D. Butler	37	Vice President—Chief Financial Officer
Melvyn E. Foster	45	Vice President—Reservoir Engineering
Bud W. Holmes	47	Vice President—Engineering and Operations
David B. McClelland	43	Vice President—Drilling and Geosciences
Jennifer L. Palko	40	Vice President—Business Development and Engineering
James R. Plemons	45	Vice President—Business Development and Land
John C. Souders	42	Vice President—Controller
Gregory A. Beard	42	Director
Ted A. Gardner	56	Director
Wilson B. Handler	29	Director
Sam Oh	43	Director
Mark A. Stevens	50	Director
Rakesh Wilson	38	Director

Robert C. Reeves—President, Chief Executive Officer and Director. Mr. Reeves has been Athlon's President and Chief Executive Officer since its formation in August 2010. Prior to Athlon's formation, Mr. Reeves was Senior Vice President, Chief Financial Officer and Treasurer of Encore Energy Partners GP LLC, the general partner of Encore Energy Partners LP, from February 2007 until March 2010, and Corporate Secretary from May 2008 to August 2010. Mr. Reeves was also the Senior Vice President, Chief Financial Officer and Treasurer of Encore Acquisition Company ("EAC") from November 2006 until March 2010, and Corporate Secretary from May 2008 to August 2010. Mr. Reeves served as Senior Vice President, Chief Accounting Officer, Controller and Assistant Corporate Secretary of EAC from November 2005 until November 2006. He served as EAC's Vice President, Controller and Assistant Corporate Secretary from August 2000 until October 2005. He served as Assistant Controller of EAC from April 1999 until August 2000. Prior to joining EAC, Mr. Reeves served as Assistant Controller for Hugoton Energy Corporation. Mr. Reeves received his Bachelor of Science degree in Accounting from the University of Kansas. He is a Certified Public Accountant. Based upon Mr. Reeves' extensive background in operations and management, having served in various high-level executive roles, as well as his strong financial background and his experience with Athlon, which provide him with a unique understanding of our business and the operational, financial and strategic issues that energy companies face, we believe that Mr. Reeves possesses the requisite set of skills to serve as a member of our Board of Directors.

Nelson K. Treadway—Senior Vice President—Business Development and Land. Mr. Treadway has been Athlon's Senior Vice President—Business Development and Land since its formation in August 2010. Prior to Athlon's formation, Mr. Treadway served as Senior Vice President—Land of Encore Energy Partners GP LLC and EAC from February 2008 to March 2010. Mr. Treadway served as Vice President—Land of EAC from April 2003 to February 2008. He served as a Vice President—Land at Encore Energy Partners GP LLC from February 2007 to February 2008. From May 2000 to April 2003, Mr. Treadway held various positions of increasing responsibility in EAC's land department. Prior to EAC, he served as a landman at Coho Resources. Mr. Treadway received a Bachelor of Science degree in Petroleum Land Management from the University of Southwestern Louisiana.

William B. D. Butler—Vice President—Chief Financial Officer. Mr. Butler has been Athlon's Vice President—Chief Financial Officer since March 2013. Prior to joining Athlon, Mr. Butler served as Managing Director for Stephens Inc. from August 2010 to March 2013, where he developed and led its Exploration & Production research practice. Previously, he was Vice President and Assistant Treasurer of XTO Energy Inc. from June 2003 until June 2010. During his seven-year tenure, XTO completed 21 capital raises, including public equity, senior notes and bank debt, for more than $15 billion in aggregate proceeds to fund XTO's growth strategy. From June 2000 to June 2003, Mr. Butler served at Stephens Inc. as an investment banker. Mr. Butler received a Bachelor of Science degree in Commerce from Washington & Lee University with special attainments in Business Administration and History.

Melvyn E. Foster—Vice President—Reservoir Engineering. Mr. Foster has been Athlon's Vice President—Reservoir Engineering since its formation in August 2010. Prior to Athlon's formation, Mr. Foster was Reservoir Engineering Manager—North Region of Denbury Resources, Inc. from April 2010 to August 2010. Mr. Foster was Northern Region Reservoir Engineering Manager of EAC from December 2007 to April 2010. From April 2002 to December 2007, Mr. Foster held various positions of increasing responsibility in EAC's engineering department. Prior to EAC, he served in various engineering positions at Phillips Petroleum Company. Mr. Foster received his Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin and his Master of Science degree in Petroleum Engineering from the University of Houston.

Bud W. Holmes—Vice President—Engineering and Operations. Mr. Holmes has been Athlon's Vice President—Engineering and Operations since its formation in August 2010. Prior to Athlon's formation, Mr. Holmes served as Northern Region Production Manager and member of the Strategic Management Team of EAC from October 2003 until March 2010. Mr. Holmes served as Northern Region Senior Operations Engineer from April 2001 until October 2003. Prior to joining EAC, Mr. Holmes served in various reservoir, production and drilling engineering positions for Louis Dreyfus Natural Gas, Union Pacific Resources and Shell Western E&P. Mr. Holmes received his Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma, graduating with top honors.

David B. McClelland—Vice President—Drilling and Geosciences. Mr. McClelland has been Athlon's Vice President—Drilling and Geosciences since its formation in August 2010. Prior to Athlon's formation, Mr. McClelland was the Geoscience Manager—Southern Region for EAC, from February 2007 to June 2010, and he was a Senior Geologist from March 2004 to January 2007 at EAC. Prior to EAC, he was a Geologist at Anadarko Petroleum Company and held various geosciences positions at Union Pacific Resources and Cross Timbers Oil Company. Mr. McClelland received his Bachelor of Science degree in Geology from the University of Texas at Arlington. He also received his Master of Science degree in Geology from the University of Texas at Arlington. Mr. McClelland is a licensed professional geoscientist in the State of Texas, and is a 16 year member of the American Association of Petroleum Geologists.

Jennifer L. Palko—Vice President—Business Development and Engineering. Ms. Palko has been Athlon's Vice President—Business Development and Engineering since its formation in August 2010. Prior to Athlon's formation, Ms. Palko served as the Reserves & Planning Engineering Manager and a member of the Strategic Management Team of EAC from October 2003 until March 2010. Prior to serving as the Reserves & Planning Engineering Manager, Ms. Palko held various positions of increasing responsibility in EAC's engineering department from May 2001 until October 2003. Prior to joining EAC, Ms. Palko served as an Independent Petroleum Consultant at Cawley, Gillespie & Associates, Inc. from September 2000 until May 2001. Prior to joining Cawley, Gillespie & Associates, Inc., Ms. Palko served in various reservoir and operations engineering positions at Union Pacific Resources from May 1995 until September 2000. Ms. Palko received her Bachelor of Science degree in Petroleum Engineering from Texas A&M University, graduating first in her class with top honors.

James R. Plemons—Vice President—Business Development and Land. Mr. Plemons has been Athlon's Vice President—Business Development and Land since its formation in August 2010. Prior to the Partnership's formation, Mr. Plemons served as the Southern Region Land Manager of Encore Energy Partners GP LLC and EAC from January 2007 to June 2010. Prior to serving as Southern Region Land Manager, Mr. Plemons served in several roles with increasing responsibility in EAC's land department from June 2004 to December 2006. Prior to EAC, he served as a landman at Wagner Oil Company. Mr. Plemons received a Bachelor of Science degree in Marketing from Sam Houston State University.

John C. Souders—Vice President—Controller. Mr. Souders has been Athlon's Vice President—Controller since July 2011 and was Director of Accounting from March 2011 until his promotion in July 2011. Prior to Athlon's formation, Mr. Souders served as a Senior Accounting Manager at EAC from May 2007 until February 2011. Prior to EAC, Mr. Souders served as an Accounting Manager at Sabre Holdings and as an auditor at Ernst & Young. Mr. Souders has a Bachelor of Science degree in Economics from Texas A&M University and a Masters in Accounting from North Texas University. He is a Certified Public Accountant.

Gregory A. Beard—Director. Mr. Beard has been a director of our Board since April 2013. Mr. Beard is currently a Senior Partner at Apollo. Mr. Beard joined the firm in June 2010 as the Global Head of Natural Resources, based in the New York office. Mr. Beard joined Apollo with 19 years of investment experience, the last ten of which were with Riverstone Holdings where he was a founding member, Managing Director and lead deal partner in many of the firm's top oil and natural gas and energy service investments. While at Riverstone, Mr. Beard was involved in all aspects of the investment process including sourcing, structuring, monitoring and exiting transactions. Mr. Beard began his career as a Financial Analyst at Goldman Sachs, where he played an active role in that firm's energy-sector principal investment activities. Mr. Beard has served on the board of directors of many oil and natural gas companies including, Belden & Blake Corporation, Canera Resources, Cobalt International Energy, Eagle Energy, Legend Natural Gas I-IV, Mariner Energy, Phoenix Exploration, Titan Operating, and Vantage Energy. Mr. Beard has also served on the board of directors of various oilfield services companies, including CDM Max, CDM Resource Management, and International Logging. Mr. Beard currently serves on the board of directors of Apex Energy, LLC, Double Eagle Energy Holdings, LLC, EP Energy Corporation, NRI Management Group, LLC, Pinnacle Agriculture Holdings, LLC, Talos Energy, LLC and Virginia Uranium. Mr. Beard received his Bachelor of Arts degree from the University of Illinois at Urbana. Based upon Mr. Beard's extensive investment and management experience, particularly in the energy sector, his strong financial background and his service on the boards of multiple oil and natural gas exploration and production companies and oilfield services companies, which have provided him with a deep working knowledge of our operating environment, we believe that he possesses the requisite skills to serve as a member of our Board of Directors.

Ted A. Gardner—Director. Mr. Gardner has been a director of our Board since August 2013. Mr. Gardner has been a Managing Partner of Silverhawk Capital Partners in Charlotte, North Carolina since 2005. Mr. Gardner is also currently a director of Summit Materials Holdings, Spartan Energy Partners, Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Formerly, he was a director and Chairman of the Compensation Committee of Kinder Morgan, Inc. from 1999 to 2007 and was a director and Chairman of the Audit Committee of Encore Acquisition Company from 2001 to 2010. Mr. Gardner also served as Managing Partner of Wachovia Capital Partners and was a Senior Vice President of Wachovia Corporation from 1990 to June 2003. Based upon his prior management, business and leadership experience, as well as his previous board experience with other publicly-held companies in the energy sector, we believe that Mr. Gardner possesses the requisite set of skills to serve as a member of our Board of Directors.

Wilson B. Handler—Director. Mr. Handler has been a director of our Board since November 2013. Mr. Handler joined Apollo in 2011 and is a member of the Natural Resources group. Prior to joining Apollo, Mr. Handler was an investment professional at First Reserve, where he was involved in the execution and monitoring of investments in the energy sector. Previously, he worked in the Investment Banking Division at Lehman Brothers in the Natural Resources group. Currently, Mr. Handler serves on the board of directors of EP Energy Corporation. Mr. Handler graduated from Dartmouth College with an AB in Economics and Government. Given Mr. Handler's extensive investment experience, his knowledge of the Company and experience in the energy industry, we believe he possesses the requisite skills to serve as a member of our Board.

Sam Oh—Director. Mr. Oh has been a director of our Board since April 2013. Mr. Oh is currently a Senior Partner at Apollo. Mr. Oh joined the firm in April 2008 and is one of the original founding members of Apollo's Natural Resources group. Prior to joining Apollo, Mr. Oh was with Morgan Stanley's Commodities Department where he led principal investments for the group. While at Morgan Stanley, Mr. Oh launched a successful oil and natural gas fund, Helios Energy/Royalty Partners, and sat on the board of several portfolio companies. Mr. Oh has 20 years of experience, including 13 years of principal investing. He also has a broad range of experience in the commodities markets including risk management and structured products. Since joining Apollo, Mr. Oh has been actively involved in Apollo's E&P investments, including leading the Parallel Petroleum acquisition in 2009. Mr. Oh was formerly Chairman of the Board of Parallel Petroleum and is a director of EP Energy Corporation. Mr. Oh received a Bachelor of Science degree from the University of Pennsylvania's Wharton School of Business and an MBA from the Yale School of Management. He is also a Certified Public Accountant and a Chartered Financial Analyst. Based upon Mr. Oh's strong management experience and extensive background in commodities markets having overseen various complex commodities investments, as well as his experience with Athlon and his service on multiple boards of directors, we believe that Mr. Oh possesses the requisite set of skills to serve as a member of our Board of Directors.

Mark A. Stevens—Director. Mr. Stevens has been a director of our Board since October 2013. Mr. Stevens is currently a tax consultant for Morningstar Partners. He previously served as Senior Vice President—Taxation of XTO Energy Inc. for 22 years from 1988 until his retirement in 2010. Prior to joining XTO, Mr. Stevens was an Accountant at Meridian Oil and Pennzoil Corp. He also serves on the Board of HomeBank Texas. Mr. Stevens received a BBA in Accounting from Harding University and is also a CPA. Based upon his prior management, business and leadership experience, as well as his previous board experience with other publicly-held companies in the energy sector, we believe that Mr. Stevens possesses the requisite set of skills to serve as a member of our Board of Directors.

Rakesh Wilson—Director. Mr. Wilson has been a director of our Board since April 2013. Mr. Wilson is a Partner of Apollo and joined Apollo in March 2009. Prior to joining Apollo, Mr. Wilson was at Morgan Stanley's Commodities Department in the principal investing group responsible for generating, evaluating and executing investment ideas across the energy sector. Mr. Wilson began his career at Goldman Sachs in equity research and then moved to its investment banking division in New York and Asia. Mr. Wilson currently serves on the boards of directors of EP Energy and Talos Energy and previously served as a director of Parallel Petroleum. Mr. Wilson graduated from the University of Texas at Austin and received his MBA from INSEAD, Fontainebleau, France. He has also taught business courses at universities in China. We believe that Mr. Wilson's extensive international investment and risk management experience, his knowledge of Athlon and his service on multiple boards have provided him with a strong understanding of the financial, operational and strategic issues facing public companies in our industry, and that he possesses the requisite set of skills to serve as a member of our Board of Directors.

Our Board of Directors currently consists of seven members. As a result of this offering, we will cease to be a "controlled company." The Board of Directors has taken, and will continue to take, all action necessary to comply with the applicable NYSE rules, including appointing a majority of independent directors to the Board of Directors and ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted "phase-in" period. We will, however, remain subject to the requirement that we have an audit committee composed entirely of independent members.

Our stockholders agreement 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 or decreased at any time to other than seven directors, the Apollo Funds' 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. As a result of the size of their ownership of our common stock, the Apollo Funds are able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions.

Our Board of Directors is divided into three classes. The members of each class will serve staggered, three-year terms (other than with respect to the initial terms of the Class I and Class II directors, which will be one and two years, respectively). Upon the expiration of the term of a class of directors, directors in that class will be elected for three-year terms at the annual meeting of stockholders in the year in which their term expires. The classes are composed as follows:

Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of our directors. This classification of our Board of Directors may have the effect of delaying or preventing changes in control.

At each annual meeting, our stockholders will elect certain of our directors. Our executive officers and key employees serve at the discretion of our Board of Directors. Directors may be removed for cause by the affirmative vote of the holders of a majority of our common stock so long as at least 33¹/3% of the voting power of all our shares is owned by the Apollo Funds and the Apollo Funds cast their votes in favor of the proposed action. At any other time, directors may be removed for cause only by the affirmative vote of at least 66²/3% of the voting power of our common stock.

Under our stockholders agreement, until such time as the Apollo Funds no longer beneficially own at least 33¹/3% of our outstanding common stock, a majority of the Board of Directors, including a majority of the directors designated to our Board of Directors by the Apollo Funds, must approve certain of our significant business decisions before we are permitted to take action, including each of the following:

Please read "—Composition of Our Board of Directors" for a description of the Apollo Funds' rights to nominate a certain number of directors.

Our Board of Directors has determined that, under NYSE listing standards and taking into account any applicable committee standards and rules under the Exchange Act, Messrs. Gardner and Stevens are independent directors. Within one year of the date of effectiveness of the registration statement of our initial public offering, we will have a third independent director. Mr. Reeves is not considered independent under any general listing standards due to his current employment relationship with us.

We have an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee, and may have such other committees as the Board of Directors shall determine from time to time. Each of the standing committees of the Board of Directors will have the composition and responsibilities described below.

Messrs. Gardner and Stevens serve as the members of our Audit Committee. We will appoint a third independent director to our Audit Committee before August 1, 2014. Our Board of Directors has determined that Messrs. Gardner and Stevens are Audit Committee financial experts as defined by the SEC. Each member of the Audit Committee meets or will meet criteria for independence of Audit Committee members set forth in Rule 10A-3(b)(1) under the Exchange Act.

The principal duties of the Audit Committee are to assist the Board of Directors in fulfilling its responsibility to oversee management regarding:

Robert C. Reeves, Gregory A. Beard, Sam Oh, Rakesh Wilson and Ted A. Gardner serve as the members of our Compensation Committee. The principal duties of the Compensation Committee are to:

Ted A. Gardner, Gregory A. Beard, Sam Oh and Rakesh Wilson serve as the members of our Nominating and Corporate Governance Committee. The principal duties and responsibilities of our Nominating and Corporate Governance Committee will be the following:

Our Board of Directors has adopted a code of business conduct and ethics (the "Code of Conduct") that applies to all directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Conduct is available in the Corporate Governance section of our website at www.athlonenergy.com. The contents of our website are not incorporated by reference herein or otherwise a part of this prospectus. The purpose of the Code of Conduct is to promote honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships; to promote full, fair, accurate, timely and understandable disclosure in periodic reports required to be filed by us; and to promote compliance with all applicable rules and regulations that apply to us and our officers.

Our Board of Directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

This executive compensation disclosure provides an overview of the 2013 executive compensation program for our named executive officers ("NEOs") identified below. For 2013, our NEOs were:

The following summarizes the total compensation awarded to, earned by or paid to our NEOs for the periods indicated:

						Stock Awards

Name and Principal Position	Year		Salary	Bonus(1)	Non-Equity Incentive Plan Compensation(2)	Athlon Holdings LP Class B Interests(3)	Athlon Energy Inc. Restricted Stock Units(4)	All Other Compensation(5)	Total
Robert C. Reeves		2013	$470,000	$285,000	$570,000	$100,170	$4,709,625	$31,600	$6,166,395
President, Chief Executive Officer and Director		2012	374,583	—	385,000	—	—	26,539	786,122
Nelson K. Treadway		2013	293,750	120,000	240,000	29,790	1,983,000	26,313	2,692,853
Senior Vice President—Business Development and Land		2012	279,375	—	206,225	—	—	22,401	508,001
William B.D. Butler		2013	223,333	108,750	217,500	116,347	1,437,675	17,200	2,120,805
Vice President—Chief Financial Officer

(1): Represents one-time special bonuses paid to our NEOs to reward their service in connection with the successful consummation of our initial public offering of common stock in August 2013.
(2): Our semi-annual cash incentive program provides for two payouts per year, with the first payment made following completion of the first half of the year and the second payment made following year-end. The amount shown for 2013 represents the cash incentive awards paid to our NEOs under this incentive program with respect to performance during the first half of 2013 and the amount expected to be paid with respect to the second half of 2013 depending upon our Compensation Committee's assessment of NEO performance and our operating results. For additional information, please read "—Narrative Disclosure to Summary Compensation Table—Cash Bonuses."
(3): The amount shown represents the fair value on the grant date of Class B interests in Athlon Holdings LP granted in 2013 prior to the completion of our IPO, calculated in accordance with FASB ASC Topic 718, excluding the effect of estimated forfeitures. The grant date fair value was determined using an option pricing model using the following assumptions:

The primary elements of compensation for the NEOs are base salary, cash bonuses and long-term equity-based compensation awards. The NEOs also receive certain retirement, health, welfare and additional benefits as described below.

Compensation Element	Characteristics	Primary Objective

Base salary	Fixed annual cash compensation. Salaries may be increased from time to time based on the NEOs' responsibilities and performance.	Recognize performance of job responsibilities and attract and retain talented employees.
Cash bonuses	Performance-based semi-annual cash incentive.	Encourage focus on near-term performance goals and reward achievement of those goals.
Long-term equity incentives	Equity-based compensation awards subject to time and performance based vesting provisions.	Emphasize our long-term growth, encourage maximizing equity value and retain talented employees.
Severance provisions	Salary continuation and COBRA reimbursement upon certain qualifying terminations.	Encourage continued attention and dedication of key individuals and focus their attention when considering strategic alternatives.
Retirement savings 401(k) plan	Qualified 401(k) retirement plan benefits are available for our NEOs and all other full-time employees.	Provide an opportunity for tax-efficient savings.
Health and welfare benefits	Health and welfare benefits are available to our NEOs and other full-time employees.	Provide benefits to meet the health and welfare needs of our employees and their families.

Compensation Decisions. Compensation decisions for our NEOs are generally made by our Compensation Committee and for 2013 were also approved by the Board. In making compensation decisions, the Compensation Committee and the Board considered the recommendations of our Chief Executive Officer as well as the results of a compensation study performed by our independent compensation consultant, Longnecker and Associates, or "Longnecker," which provided a comparison of our executives' compensation levels to the compensation of similarly situated executives at a group of peer companies in our industry. Longnecker was engaged by management to perform executive compensation consulting services for us in 2013 and did not perform any other services for us in 2013. We do not believe that Longnecker's work for us in 2013 has given rise to any conflict of interest.

Base Salary. Base salaries for our NEOs have generally been set at levels deemed necessary to attract and retain individuals with superior talent. While the Board will review and may adjust each NEO's salary from time to time, Messrs. Treadway's and Butler's employment agreements provide that their respective salary will not be reduced for two years after the effective date of his agreement and Mr. Reeves' employment agreement provides that his base salary will never be reduced.

In connection with our initial public offering, the Board approved salary increases for our NEOs based upon the responsibilities and performance of each NEO and to better align total compensation with competitive pay levels for similarly situated public companies, based on recommendations from our independent compensation consultant, Longnecker and Associates. The base salaries of our NEOs before and after the 2013 increase are set forth in the following table:

Cash Bonuses. Each of our NEOs is eligible to participate in a semi-annual cash incentive program which provides participants with an opportunity to earn cash bonus awards generally based on individual and company performance. Annual target bonus levels for each of our NEOs other than Mr. Reeves are established by the Board of Directors at the beginning of each year, subject to mid-year adjustment, and are based on a percentage of their respective base salary. Mr. Reeves' annual target bonus level of 100% is set forth in his employment agreement and was established based upon individual negotiations at the time of his commencement of employment. For 2013, Messrs. Treadway and Butler had an annual target bonus level of 80% and 75%, respectively.

Historically, including for 2013, with respect to assessment of company performance, the bonus awards for our NEOs have not been based on specific pre-determined performance targets or goals. Rather, we have generally considered our overall operational performance for the applicable year as a guide in determining award payout levels and have maintained discretion to adjust awards in circumstances where individual performance may warrant such an adjustment. For the first half of 2013, we determined to pay bonuses to each of our NEOs at 100% of their respective first-half target bonus levels (i.e., 50% of their total annual target bonus levels) and did not make any individual performance adjustments to these awards. Our decision in this regard was based primarily on overall strong company performance with respect to certain operational performance metrics, which included rate of return on drilling capital, our net asset value, drilling costs per well, production volumes and LOE per BOE. We focused on operating metrics of this type in determining cash bonus awards for our NEOs, rather than on financial metrics such as revenue or net income because such financial metrics are influenced by commodity prices, which can fluctuate based on macro-economic factors that are beyond the control of our NEOs.

In addition to our regular semi-annual cash incentive awards, for 2013, we paid each of our NEOs an additional one-time special cash bonus to reward their service in connection with the successful completion of our initial public offering in 2013. These one-time cash bonuses were each in an amount equal to 50% of their annual target bonus levels under our semi-annual cash incentive program.

Long-Term Equity-Based Compensation Awards. In connection with our initial public offering, we adopted the Athlon Energy Inc. 2013 Incentive Award Plan, under which our Board or Compensation Committee may make periodic grants of equity and equity-based awards from time to time to our NEOs and other key employees. For additional information, please read "—Executive Compensation Plans—2013 Incentive Award Plan."

In September 2013, our NEOs received an award of restricted stock units, or RSUs, granted under our 2013 Incentive Award Plan as set forth in the table below.

These awards will vest in three equal annual installments, with the first installment vesting on the first anniversary of the consummation of our initial public offering. One half of each annual installment is subject to performance based vesting conditions pursuant to which the number of shares that will vest will be determined based on our total stockholder return for the one-year period ending on the vesting date, as compared to the total stockholder return for that period of a specified peer group of publicly-traded companies in our industry. With respect to the performance-based portion of the award, (i) no portion of the award will be earned if our total shareholder return is below the 25^th percentile of the total shareholder return for the companies in our peer group, (ii) 100% of the target award level will be earned if our total shareholder return is between the 25^th percentile and 75^th percentile of the total shareholder return for the companies in our peer group and (iii) 200% of the target award level will be earned if our total shareholder return is at or above the 75^th percentile of the total shareholder return for the companies in our peer group.

Retirement, Health, Welfare and Additional Benefits. The NEOs are eligible to participate in such employee benefit plans and programs as we may from time to time offer to our other full-time employees, subject to the terms and eligibility requirements of those plans. The NEOs are also eligible to participate in a tax-qualified 401(k) defined contribution plan to the same extent as all of our other full-time employees. For 2013, we anticipate making a fully vested safe harbor non-elective contribution on behalf of each of the plan's participants equal to 3% of that participant's salary for the year.

The outstanding equity awards held by our NEOs as of December 31, 2013 were as follows:

In connection with the consummation of our initial public offering, we entered into new employment agreements with each of our NEOs. These agreements provide for an initial term of three years for Mr. Reeves and two years for Messrs. Treadway and Butler, are subject to automatic renewal for a one-year period and contain (i) compensation provisions, including provisions regarding base salary, cash incentive bonuses and other benefits, (ii) termination and severance provisions (discussed more in detail below) and (iii) noncompete, nonsolicit and nondisclosure provisions, with a restriction period of one year for the noncompete and nonsolicit provisions.

Mr. Reeves' Severance and Change in Control Benefits. Mr. Reeves' employment agreement provides that if we terminate Mr. Reeves' employment for cause, he resigns without good reason or he does not extend his term of employment, then he is entitled to receive: (i) the portion of his base salary earned through the date of termination but not yet paid, plus any accrued vacation earned but not used through the date of termination; (ii) any cash incentive bonus earned but not yet paid; (iii) any expenses owed to him; and (iv) any amount accrued arising from his participation in, or benefits accrued under any employee benefits plans, programs or arrangements. Any rights to salary, cash bonus or other benefits will then cease.

However, if Mr. Reeves is terminated without cause, resigns with good reason or we do not extend his term of employment and Mr. Reeves signs a release within 45 days, he is entitled, in addition to the items listed in the above paragraph, to (i) receive an amount of cash equal to four times the annual base salary in effect as of the date of termination payable 50% in a lump sum within 60 days following his separation from service and 50% over the subsequent twelve months, in accordance with regular payroll practices, and (ii) have us pay directly or reimburse him for COBRA premiums if he (or his dependents) elect to receive continued healthcare coverage pursuant to COBRA until the earlier of two years or the last day of the applicable COBRA period.

In addition to the items listed in the paragraph above, if Mr. Reeves is terminated without cause, he resigns with good reason or we do not extend his term of employment, in any case within one year following the date of a change in control, then in lieu of the amount of cash listed above, he is entitled to receive an amount in cash equal to three times his annual base salary in effect as of the date of termination, plus three times the greater of the average of his previous two years' bonus payments or his target bonus.

If Mr. Reeves is terminated due to death or disability and, in the case of disability, he signs a release within 45 days, he is additionally entitled to (i) receive an amount of cash equal to 25% of his base salary, payable in lump sum on the 60^th day following his separation from service and (ii) have us pay directly or reimburse him for COBRA premiums if he (or his dependents) elect to receive continued healthcare coverage pursuant to COBRA for three months.

Good reason is defined in Mr. Reeves' employment agreement generally to mean the occurrence of any of the following events without his express written consent: (i) any reduction in his base salary; (ii) any material breach by us of the employment agreement; (iii) his duties or responsibilities for us or our successor are materially reduced or there is any material change in his title or any material change in the types of positions reporting to him or the type of position to whom he reports; or (iv) any transfer of his primary place of employment of more than 25 miles from 420 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102, provided that such transfer increases his commute by more than 25 miles.

In addition, Mr. Reeves' award agreement granting his 2013 RSU award, which is described in more detail under the heading "—Long-Term Equity-Based Compensation Awards," provides that 100% of the maximum number of shares subject to the RSU award will vest upon a change in control.

Other NEOs' Severance and Change in Control Benefits. Messrs. Treadway's and Butler's employment agreements provide that if either NEO's employment is terminated (i) for cause, due to death or disability, (ii) due to resignation without good reason or (iii) either party decides not to extend the term of employment, then each is entitled to (a) the portion of his base salary earned through the date of termination but not yet paid, plus any accrued vacation earned but not used through the date of termination, (b) any expenses owed to him and (c) any amount accrued arising from his participation in, or benefits accrued under any employee benefits plans, programs or arrangements. Any rights to salary, cash bonus or other benefits will then cease.

However, if Messrs. Treadway or Butler is terminated without cause or resigns for good reason and signs a release within 45 days, then each is entitled, in addition to the items listed in the above paragraph, to (i) receive an amount of cash equal to his annual base salary payable over the twelve-month period from his separation of service, in accordance with regular payroll practices, and (ii) have us pay directly or reimburse him for COBRA premiums if he (or his dependents) elect to receive continued healthcare coverage pursuant to COBRA until the earlier of twelve months, the date the covered dependents are no longer eligible or the date he becomes eligible to receive substantially comparable coverage from another employer.

If either Messrs. Treadway or Butler is terminated without cause or resigns for good reasons or we do not extend his term of employment, in either case within one year following the date of a change in control, then (i) in lieu of the amount of cash listed above, each is entitled to receive an amount in cash equal to two and a half times his annual base salary in effect as of the date of termination, plus two and a half times the greater of the average of his previous two years' bonus payments or his target bonus, and (ii) in lieu of the healthcare continuation listed above, we will continue to pay or reimburse his healthcare coverage pursuant to COBRA until the earlier of 18 months, the date the covered dependents are no longer eligible or the date he becomes eligible to receive substantially comparable coverage from another employer.

Cause is defined in the employment agreements generally as the occurrence or existence of any of the following events: (i) the NEO's willful engagement in material mismanagement in providing services to us or our affiliates; (ii) the NEO's willful engagement in misconduct that he knew, based on facts known to him, could reasonably be expected to be materially injurious to us or our affiliates; (iii) the NEO's material breach of the employment agreement; (iv) the NEO's conviction of, or entrance into a plea bargain or settlement admitting guilt for, any felony, under the laws of the United States, any state or the District of Columbia; or (v) each NEO being the subject of any order, judicial or administrative, obtained or issued by the SEC, for any securities violation involving fraud. Good reason is defined in a similar manner to Mr. Reeves' employment agreement.

Change in Control is defined to have the same meaning as in the Athlon Energy Inc. 2013 Incentive Award Plan, without regard to any amendments that may be adopted after the date of this offering.

In addition, Messrs. Treadway's and Butler's award agreements granting their 2013 RSU awards, which are described in more detail under the heading "—Long-Term Equity-Based Compensation Awards," provide that 100% of the maximum number of shares subject to the RSU award will vest upon a change in control.

The following summarizes the material terms of the long-term incentive compensation plan in which our NEOs are eligible to participate.

We grant equity and equity-based compensation awards to our NEOs and other key employees on a periodic basis to align compensation with our performance. These awards are granted under the Athlon Energy Inc. 2013 Incentive Award Plan that we adopted in conjunction with our initial public offering. The material terms of the Athlon Energy Inc. 2013 Incentive Award Plan, which we refer to as the Plan, are described in more detail below.

The principal purpose of the Plan is to attract, retain and engage selected employees, consultants and directors through the granting of equity and equity-based compensation awards.

Our and our subsidiaries' employees, consultants and directors, including our NEOs, are eligible to receive awards under the Plan. The Compensation Committee administers the Plan. The Compensation Committee is authorized to delegate its duties and responsibilities as plan administrator to subcommittees comprised of our directors and/or officers, subject to certain limitations. Our Board of Directors administers the Plan with respect to awards to non-employee directors.

Subject to the express terms and conditions of the Plan, the plan administrator has the authority to make all determinations and interpretations under the plan, prescribe all forms for use with the plan and adopt, amend and/or rescind rules for the administration of the plan. The plan administrator also sets the terms and conditions of all awards under the plan, including any vesting and vesting acceleration conditions.

The aggregate number of our shares of common stock available for issuance pursuant to awards granted under the Plan will be the sum of 8,400,000 shares, subject to adjustment as described below plus an annual increase on the first day of each calendar year beginning January 1, 2014 and ending on and including the last January 1 prior to the expiration date of the Plan, equal to the least of (i) 12,000,000 shares, (ii) 4% of the shares outstanding (on an as-converted basis) on the final day of the immediately preceding calendar year and (iii) such smaller number of shares as determined by the Board. Please read "—Certain Transactions." This number will also be adjusted due to the following shares becoming eligible to be used again for grants under the Plan:

Shares granted under the Plan may be treasury shares, authorized but unissued shares, or shares purchased in the open market. The payment of cash dividends in conjunction with any outstanding awards will not be counted against the shares available for issuance under the Plan. In addition, if we or one of our subsidiaries acquires or combines with another company that has shares available for grant pursuant to a qualifying equity plan, we may use those shares (until such date as they could not have been used under such entity's plan) to grant awards pursuant to the Plan to individuals who were not providing services to us immediately prior to the acquisition or combination.

The Plan does not provide for individual limits on awards that may be granted to any individual participant under the Plan. Rather, the amount of awards to be granted to individual participants is determined by our Board of Directors or the Compensation Committee from time to time, as part of their compensation decision-making processes, provided, however, that the Plan does not permit awards having a grant date fair value in excess of $700,000 to be granted to our non-employee directors in any year.

The Plan provides for the grant of stock options (including non-qualified stock options, or "NQSOs," and incentive stock options, or "ISOs"), restricted stock, dividend equivalents, stock payments, restricted stock units, or "RSUs," performance awards, stock appreciation rights, or "SARs," and other equity-based and cash-based awards, or any combination thereof. Awards under the Plan will be set forth in award agreements, which will detail the terms and conditions of the awards, including any applicable vesting and payment terms and post-termination exercise limitations as well as any other consequences with respect to the awards upon a termination of the applicable eligible individual's service. Equity-based awards will generally be settled in shares of our common stock, but the plan administrator may provide for cash settlement of any award. A brief description of each award type follows.

The plan administrator has broad discretion to equitably adjust the provisions of the Plan and the terms and conditions of existing and future awards, including with respect to aggregate number and type of shares subject to the Plan and awards granted pursuant to the Plan, to prevent the dilution or enlargement of intended benefits and/or facilitate necessary or desirable changes in the event of certain transactions and events affecting our shares, such as stock dividends, stock splits, mergers, acquisitions, consolidations and other corporate transactions. In the case of certain events or changes in capitalization that constitute "equity restructurings," equitable adjustments will be non-discretionary. In the event of a change in control where the acquirer does not assume or replace awards granted under the Plan, such awards may be subject to accelerated vesting so that 100% of such awards will become vested and exercisable or payable, as applicable, and will be exercisable for a period of fifteen days following notice of such event from the plan administrator and, if not exercised, will terminate upon the expiration of such fifteen-day period. The plan administrator may also provide for the acceleration, cash-out, termination, assumption, substitution or conversion of awards in the event of a change in control or certain other unusual or nonrecurring events or transactions. A "change in control" is defined in the Plan to mean (i) the acquisition by a person or group of more than 50% of the total combined voting power of our outstanding securities, (ii) during any consecutive two-year period, the

replacement of a majority of our incumbent directors with directors whose election was not supported by at least two-thirds of our incumbent directors, (iii) a merger, consolidation, reorganization or business combination or the sale of substantially all of our assets after which the Apollo Funds and its affiliates cease to own at least 50% of the combined voting power in us, in each case, other than a transaction which results in our voting securities before such transaction continuing to represent or being converted into a majority of the voting securities of the surviving entity and after which no person or group owns a majority of the combined voting power of the surviving entity or (iv) our liquidation or dissolution; provided, however, any event or occurrence whereby the Apollo Funds or a group consisting of our directors, executive officers or members of our management acquire voting control of us will not constitute a change in control for purposes of the Plan.

With limited exceptions for estate planning, domestic relations orders, certain beneficiary designations and the laws of descent and distribution, awards under the Plan are generally non-transferable prior to vesting and are exercisable only by the participant. The price per share of a stock option or SAR may not be decreased and an underwater stock option or SAR may not be replaced or cashed out without stockholder approval. With regard to tax withholding, exercise price and purchase price obligations arising in connection with awards under the Plan, the plan administrator may, in its discretion, accept cash or check, our shares that meet specified conditions, a "market sell order" (or other cashless broker-assisted transaction) or such other consideration as it deems suitable.

Our Board of Directors may terminate, amend or modify the Plan at any time and from time to time. However, we must generally obtain stockholder approval to increase the number of shares available under the Plan (other than in connection with certain corporate events, as described above) or to the extent required by applicable law, rule or regulation (including any applicable stock exchange rule).

The Plan will expire on, and no option or other award may be granted pursuant to the Plan after, the tenth anniversary of the date the plan was adopted by our Board of Directors. Any award that is outstanding on the expiration date of the Plan will remain in force according to the terms of the Plan and the applicable award agreement.

Our or our subsidiaries' officers, employees, consultants or advisors who also serve as directors do not receive additional compensation for their service as directors. Our directors who are not our or our subsidiaries' officers, employees, consultants or advisors or Apollo's officers or employees, who we refer to as our non-employee directors, receive cash and equity-based compensation for their services as directors.

Non-employee directors also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

None of our officers or employees are members of our Compensation Committee. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our Board of Directors or Compensation Committee. No member of our Board of Directors is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

To the extent any member of our Compensation Committee and affiliates of theirs has participated in transactions with us, a description of those transactions would be described in "Certain Relationships and Related Party Transactions."

In connection with our corporate reorganization, we engaged in certain transactions with certain affiliates and the limited partners of Athlon Holdings LP. Please read "Corporate Reorganization" for a description of these transactions.

Prior to our corporate reorganization, the Apollo Funds had committed approximately $400 million of capital contributions to fund our business and operations. After our corporate reorganization, the Apollo Funds have no further capital commitments.

In connection with our initial public offering, we entered into a stockholders agreement with the Apollo Funds and certain stockholders that 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 or decreased at any time to other than seven directors, the Apollo Funds' 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.

Under the stockholders agreement, if the Apollo Funds hold at least 33¹/3% of our outstanding common stock, they will have the right to engage in each of the following actions:

The stockholders agreement also provides that so long as the Apollo Funds hold at least 33¹/3% of our outstanding common stock, a majority of our Board of Directors, including a majority of the directors designated to our Board of Directors by the Apollo Funds, must approve certain of our significant business decisions before we are permitted to take action, including each of the following:

The stockholders agreement also provides that the Apollo Funds, or any employee stockholder owning at least 1% of our outstanding common stock, may make one or more written demands requiring us to register the shares of our common stock owned by the Apollo Funds or the employee stockholders. In addition, any stockholder (including the Apollo Funds) will have piggyback rights entitling them to require us to register shares of our common stock owned by them in connection with any registration statements filed by us, subject to certain exceptions. We have agreed to indemnify the Apollo Funds (to the extent they are selling stockholders in any such registration) against losses suffered by them in connection with any untrue or alleged untrue statement of a material fact contained in any registration statement, prospectus or preliminary prospectus or any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statement therein not misleading, except insofar as the same may be caused by or contained in any information furnished in writing to us by such selling stockholder for use therein.

Prior to our initial public offering, we were a 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. In October 2012, Apollo assigned its rights and obligations under the Transaction Fee Agreement to one of its affiliates, Apollo Global Securities, LLC. Since our inception through our initial public offering, we incurred transaction fees under the Transaction Fee Agreement of approximately $7.5 million in total. Upon the consummation of our initial public offering, we terminated the Transaction Fee Agreement.

Prior to our initial public offering, we were party to a Services Agreement, dated August 23, 2010, which required us to compensate Apollo for consulting and advisory services equal to the higher of (i) 1.00% of earnings before interest, income taxes, depletion, depreciation, amortization and exploration expense per quarter and (ii) $62,500 per quarter (the "Advisory Fee"); provided, however, that such Advisory Fee for any calendar year shall not exceed $500,000. The Services Agreement also provided for reimbursement to Apollo for any reasonable out-of-pocket expenses incurred while performing services under the Services Agreement. During 2013 until the termination of the Services

Agreement and during 2012 and 2011, we incurred approximately $500,000, $493,000 and $411,000, respectively, of Advisory Fees.

Upon the consummation of our initial public offering, we terminated the Services Agreement and, in connection with the termination, we paid Apollo $2.4 million (plus $132,000 of unreimbursed expenses) from us. 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) using a discount rate of 8.0%. Under the Services Agreement, we also agreed to indemnify Apollo and its affiliates and their respective limited partners, general partners, directors, members, officers, managers, employees, agents, advisors, their directors, officers and representatives for potential losses relating to the services contemplated under the Services Agreement.

Apollo Global Securities, LLC is an affiliate of the Apollo Funds and received a portion of the gross spread as an initial purchaser in our senior notes offering of approximately $0.5 million. Apollo Global Securities, LLC was also an underwriter in our initial public offering and received a portion of the discounts and commissions paid to the underwriters in our initial public offering of approximately $0.9 million. Apollo Global Securities, LLC is also an underwriter in this offering and will receive a portion of the discounts and commissions paid to the underwriters in this offering. See "Underwriting (Conflicts of Interest)."

We used a portion of the net proceeds from the senior notes offering to make a distribution to our Class A limited partners, including the Apollo Funds and our management team and employees. The Apollo Funds received approximately $73 million of the distribution and the remaining Class A limited partners received approximately $2 million, in the aggregate.

We entered into an exchange agreement with certain members of our management team and employees that held New Holdings Units after the closing of our initial public offering. Under the exchange agreement, each such holder (and certain permitted transferees thereof) may, under certain circumstances (subject to the terms of the exchange agreement), 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. As a holder exchanges its New Holdings Units, Athlon Energy Inc.'s interest in Athlon Holdings LP will be correspondingly increased.

As described under "—Exchange Agreement," certain holders of New Holdings Units may (subject to the terms of the exchange agreement) exchange such units for shares of common stock of Athlon Energy Inc. on a one-for-one basis. Athlon Holdings LP (and each of its subsidiaries treated as partnerships for United States federal income tax purposes) intends to make an election under Section 754 of the Code effective for each taxable year in which an exchange of Athlon Holdings LP units for shares of common stock occurs, which may result in an adjustment to the tax basis of the assets of Athlon Holdings LP at the time of an exchange. As a result of these exchanges, Athlon Energy Inc., which we refer to as the "corporate taxpayer," will become entitled to a proportionate share of the existing tax basis of the assets of Athlon Holdings LP. In addition, the purchase of New

Holdings Units and subsequent exchanges are expected to result in increases in the tax basis of the assets of Athlon Holdings LP that otherwise would not have been available. Both this proportionate share and these increases in tax basis may reduce the amount of tax that the corporate taxpayer would otherwise be required to pay in the future. These increases in tax basis may also decrease gains (or increase losses) on future dispositions of certain capital assets to the extent tax basis is allocated to those capital assets. The IRS may challenge all or part of the existing tax basis, tax basis increase and increased deductions, and a court could sustain such a challenge.

We entered into a tax receivable agreement with certain members of our management team and employees that held New Holdings Units after the closing of our initial public offering that provides for the payment from time to time by the corporate taxpayer to such unitholders of Athlon Holdings LP of 85% of the amount of the benefits, if any, that the corporate taxpayer is deemed to realize as a result of increases in tax basis and certain other tax benefits related to exchanges of New Holdings Units pursuant to the exchange agreement, including tax benefits attributable to payments under the tax receivable agreement. These payment obligations will be obligations of the corporate taxpayer and not of Athlon Holdings LP. For purposes of the tax receivable agreement, the benefit deemed realized by the corporate taxpayer will be computed by comparing the actual income tax liability of the corporate taxpayer (calculated with certain assumptions) to the amount of such taxes that the corporate taxpayer would have been required to pay had there been no increase to the tax basis of the assets of Athlon Holdings LP as a result of the exchanges and had the corporate taxpayer not entered into the tax receivable agreement. The term of the tax receivable agreement will continue until all such tax benefits have been utilized or expired, unless the corporate taxpayer exercises its right to terminate the tax receivable agreement for an amount based on the agreed payments remaining to be made under the agreement, the corporate taxpayer breaches any of its material obligations under the tax receivable agreement or the holders of New Holdings Units elect to terminate the tax receivable agreement, in which case the corporate taxpayer's obligations will generally be accelerated. Estimating the amount of payments that may be made under the tax receivable agreement is by its nature imprecise, insofar as the calculation of amounts payable depends on a variety of factors. The actual increase in tax basis, as well as the amount and timing of any payments under the tax receivable agreement, will vary depending upon a number of factors, including:

The step-up in basis will depend on the fair value of the New Holdings Units at conversion. Further, we do not expect to be in a tax paying position before 2019, so we cannot presently determine what the benefit or payments under the tax receivable agreement will be. In addition, there is no intent

of the holders of New Holdings Units to exchange their units for shares of our common stock in the foreseeable future.

In addition, the tax receivable agreement will provide that upon certain mergers, asset sales, other forms of business combinations or other changes of control, the corporate taxpayer's (or its successor's) obligations with respect to exchanged or acquired New Holdings Units (whether exchanged or acquired before or after such transaction) would be based on certain assumptions, including that the corporate taxpayer would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the tax receivable agreement. As a result, we could be required to make payments under the tax receivable agreement that are greater than or less than the specified percentage of the actual benefits we realize in respect of the tax attributes subject to the tax receivable agreement. Furthermore, if we elect to terminate the tax receivable agreement early, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits, which upfront payment may be made years in advance of the actual realization of such future benefits. In these situations, our obligations under the tax receivable agreement could have a substantial negative impact on our liquidity.

Decisions made in the course of running our business, such as with respect to mergers, asset sales, other forms of business combinations or other changes in control, may influence the timing and amount of payments that are received by an exchanging or selling existing owner under the tax receivable agreement. For example, the earlier disposition of assets following an exchange or acquisition transaction will generally accelerate payments under the tax receivable agreement and increase the present value of such payments, and the disposition of assets before an exchange or acquisition transaction will increase an existing owner's tax liability without giving rise to any rights of an existing owner to receive payments under the tax receivable agreement.

Payments will be generally due under the tax receivable agreement within a specified period of time following the filing of our tax return for the taxable year with respect to which the payment obligation arises, although interest on such payments will begin to accrue at a rate of LIBOR plus 300 basis points from the due date (without extensions) of such tax return.

Payments under the tax receivable agreement will be based on the tax reporting positions that we will determine. Although we are not aware of any issue that would cause the IRS to challenge a tax basis increase, the corporate taxpayer will not be reimbursed for any payments previously made under the tax receivable agreement. As a result, in certain circumstances, payments could be made under the tax receivable agreement in excess of the benefits that the corporate taxpayer actually realizes in respect of the tax attributes subject to the tax receivable agreement.

Upon 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 as described in "Corporate Reorganization."

The unitholders of Athlon Holdings LP, including Athlon Energy Inc., will incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Athlon Holdings LP. Net income of Athlon Holdings LP will generally be allocated to our unitholders (including Athlon Energy Inc.) in accordance with their percentage interest in Athlon Holdings LP. Net losses of Athlon Holdings LP will generally be allocated first to the unitholders (including Athlon Energy Inc.) in accordance with their percentage interest in Athlon Holdings LP until their capital accounts are reduced to zero, and then to the general partner. The partnership agreement of Athlon Holdings LP provides for quarterly cash distributions, which we refer to as "tax distributions," to the limited partners of Athlon Holdings LP (including Athlon Energy Inc.). Generally, these tax distributions will

be computed based on the estimate of the Board of Supervisors as to the projected deemed income tax liability of each limited partner with respect to the partnership interest of such limited partner. Tax distributions will be made only to the extent that cash is available to cover such distributions.

Pursuant to its written charter, our Audit Committee must review and approve all material related party transactions, which include any related party transactions that we would be required to disclose pursuant to Item 404 of Regulation S-K promulgated by the SEC. In determining whether to approve a related party transaction, our Audit Committee will consider a number of factors including whether the related party transaction is on terms and conditions no less favorable to us than may reasonably be expected in arm's-length transactions with unrelated parties.

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, the Apollo Funds, members of our management team and certain employees owned all of the Class A limited partner interests in Athlon Holdings LP and members of our management team and certain employees owned all of the Class B limited partner interests in Athlon Holdings LP. In the reorganization, the Apollo Funds entered into a number of distribution and contribution transactions pursuant to which the Apollo Funds exchanged their Class A limited partner interests in Athlon Holdings LP for common stock of Athlon Energy Inc. The remaining holders of Class A limited partner interests in Athlon Holdings LP have not exchanged their interests in the reorganization transactions. In addition, the holders of the Class B limited partner interests in Athlon Holdings LP exchanged their interests for common stock of Athlon Energy Inc. Upon 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 hold 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, 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.

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

The following table sets forth the beneficial ownership of our common stock immediately prior to and after this offering by:

Except as otherwise indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective directors, director nominees, named executive officers or 5% or more stockholders, as the case may be. Unless otherwise indicated, the address for each listed beneficial owner is 420 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102.

Upon the completion of this offering, the Apollo Funds will own, in the aggregate, approximately 48.5% of our outstanding common stock (or approximately 46.0% if the underwriters exercise in full their option to purchase additional shares of common stock).

													Common stock beneficially owned after the offering (assuming the underwriters' option to purchase additional shares is exercised in full)

								Common stock beneficially owned after the offering (assuming no exercise of the underwriters' option to purchase additional shares)
						Number of shares of common stock offered if the underwriters' option to purchase additional shares is exercised in full
	Common stock beneficially owned before the offering
Name and Address of Beneficial Owner(1)(4)	Number		Percentage					Number		Percentage			Number		Percentage
*Principal and Selling Stockholders*
Apollo Funds(2)		53,839,672		65.6	%		16,100,000		39,839,672		48.5	%		37,739,672		46.0	%
*Directors and Named Executive Officers*
Robert C. Reeves(3)(4)(5)(6)		4,917,779		5.9	%		—		4,917,779		5.9	%		4,917,779		5.9	%
Gregory A. Beard		—		*			—		—		*			—		*
Ted A. Gardner(4)		82,500		*			—		82,500		*			82,500		*
Wilson B. Handler		—		*			—		—		*			—		*
Sam Oh		—		*			—		—		*			—		*
Mark A. Stevens(4)		17,500		*			—		17,500		*			17,500		*
Rakesh Wilson		—		*			—		—		*			—		*
Nelson K. Treadway(3)(4)(5)(6)		1,528,997		1.9	%		—		1,528,997		1.9	%		1,528,997		1.9	%
William B. D. Butler(3)(4)(5)		505,509		*			—		505,509		*			505,509		*
Directors and executive officers as a group (13 persons)(3)(4)(5)(6)		10,016,902		11.9	%		—		10,016,902		11.9	%		10,016,902		11.9	%

includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person's ownership percentage, but not for purposes of computing any other person's percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock.

(2): The amount reported includes shares held of record by Apollo Athlon Holdings, L.P. ("Athlon Holdings") and AP Overseas VII (Athlon FC) Holdings, L.P. ("Overseas VII (Athlon FC)," together with Athlon Holdings, the "Apollo Funds"). Apollo Management VII, L.P. ("Management VII") is the manager of the Apollo Funds. AIF VII Management, LLC ("AIF VII LLC") is the general partner of Management VII. Apollo Management, L.P. ("Apollo Management") is the sole member and manager of AIF VII LLC, and Apollo Management GP, LLC ("Apollo Management GP") is the general partner of Apollo Management. Apollo Management Holdings, L.P. ("Management Holdings") is the sole member and manager of Apollo Management GP, and Apollo Management Holdings GP, LLC ("Management Holdings GP") is the general partner of Management Holdings. Leon Black, Joshua Harris and Marc Rowan are the managers, as well as executive officers, of Management Holdings GP, and as such may be deemed to have voting and dispositive control over the shares of our common stock held by the Apollo Funds. The address of the Apollo Funds is One Manhattanville Road, Suite 201, Purchase, New York 10577. The address of each of Management VII, AIF VII LLC, Apollo Management, Apollo Management GP, Management Holdings and Management Holdings GP, and Messrs. Black, Harris and Rowan, is 9 West 57th Street, 43rd Floor, New York, New York 10019.
(3): Includes New Holdings Units that are exchangeable for shares of our common stock on a one-for-one basis as follows: Mr. Reeves (727,441), Mr. Treadway (263,454), Mr. Butler (226,316) and directors and executive officers as a group (1,646,564).
(4): Includes unvested restricted stock units as follows: Mr. Reeves (71,250), Mr. Gardner (7,500), Mr. Stevens (7,500), Mr. Treadway (30,000), Mr. Butler (21,750) and directors and executive officers as a group (209,125).
(5): Excludes performance units that will vest if and to the extent predetermined performance targets are achieved assuming that performance targets are achieved as follows: Mr. Reeves (71,250), Mr. Treadway (30,000), Mr. Butler (21,750) and directors and executive officers as a group (194,125).
(6): Includes shares owned by trusts whose beneficiaries are members of the respective executive officer's family and for which the respective executive officer serves as trustee, but has no beneficial interest in the trusts as follows: Mr. Reeves (507,576), Mr. Treadway (304,545) and directors and executive officers as a group (812,121).

The following description of our amended and restated certificate of incorporation and amended and restated bylaws are summaries thereof and are qualified by reference to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which have been filed with the SEC.

Pursuant to our amended and restated certificate of incorporation, our capital stock consists of 550,000,000 authorized shares, of which 500,000,000 shares, par value $0.01 per share, are designated as "common stock" and 50,000,000 shares, par value $0.01 per share, are designated as "preferred stock." There are currently no shares of preferred stock outstanding.

Voting Rights. Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of common stock do not have cumulative voting rights in the election of directors.

Dividend Rights. Holders of common stock are entitled to receive ratably dividends if, as and when dividends are declared from time to time by our Board of Directors out of funds legally available for that purpose, after payment of dividends required to be paid on outstanding preferred stock, as described below, if any. Under Delaware law, we can only pay dividends either out of "surplus" or out of the current or the immediately preceding year's net profits. Surplus is defined as the excess, if any, at any given time, of the total assets of a corporation over its total liabilities and statutory capital. The value of a corporation's assets can be measured in a number of ways and may not necessarily equal their book value.

Liquidation Rights. Upon liquidation, dissolution or winding up of our affairs, whether voluntarily or involuntarily, the holders of common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and accrued but unpaid dividends and liquidation preferences on any outstanding preferred stock.

Other Matters. The common stock has no preemptive, subscription or conversion rights. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of our common stock are fully paid and non-assessable, and the shares of our common stock offered in this offering, upon payment and delivery in accordance with the underwriting agreement, will be fully paid and non-assessable.

Pursuant to our amended and restated certificate of incorporation, shares of preferred stock will be issuable from time to time, in one or more series, with the designations of the series, the dividend rates and whether such dividends will be cumulative or non-cumulative, the voting conversion or exchange rights of the shares of the series (if any), redemption rights, whether or not the shares of the series will be entitled to the benefit of a retirement or sinking fund, liquidation rights, the powers, preferences and relative, participation, optional or other special rights (if any), and any qualifications, limitations or restrictions thereof as our Board of Directors from time to time may adopt by resolution (and without further stockholder approval), subject to certain limitations. Each series will consist of that number of shares as will be stated and expressed in the certificate of designations providing for the issuance of the stock of the series, which number may be increased or decreased from time to time by our Board of Directors. All shares of any one series of preferred stock will be identical.

Composition of Board of Directors; Election and Removal of Directors; Number of Directors

In accordance with our amended and restated certificate of incorporation and our amended and restated bylaws, the number of directors comprising our Board of Directors is determined from time to time by our Board of Directors, and only a majority of the Board of Directors may fix the number of directors; provided that in no event shall the total number of directors be less than three nor more than fifteen. As a result of this offering, we will cease to be a "controlled company." The Board of Directors has taken, and will continue to take, all action necessary to comply with the applicable NYSE rules, including appointing a majority of independent directors to the Board of Directors and ensuring we have a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted "phase-in" period. We will, however, remain subject to the requirement that we have an audit committee composed entirely of independent members.

Following this offering, we will no longer qualify as a "controlled company" under the NYSE corporate governance standards. As a result, we will be required to comply with the NYSE corporate governance standards as follows:

We intend for our board of directors, Compensation Committee and Nominating and Corporate Governance Committee to be composed of the appropriate number of independent directors within the required time frame.

Our stockholders agreement 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 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.

We have seven directors. Within one year of our initial public offering, we will appoint at least one more additional director. Our amended and restated bylaws provides that our Board of Directors is divided into three classes of directors, with the classes to be as nearly equal in number as possible. As a result, approximately one-third of our Board of Directors will be elected at each annual meeting of stockholders, with such elections decided by plurality vote, each year. The classification of directors has the effect of making it more difficult for stockholders to change the composition of our Board of

Directors. Each director is to hold office until his successor is duly elected and qualified or until his earlier death, resignation or removal. Any vacancies on our Board of Directors may be filled only by the affirmative vote of a majority of the remaining directors, although less than a quorum. Our amended and restated certificate of incorporation provides that stockholders do not have the right to cumulative votes in the election of directors. At any meeting of our Board of Directors, except as otherwise required by law, a majority of the total number of directors then in office will constitute a quorum for all purposes. Please read "Management—Committees of the Board of Directors."

Our amended and restated bylaws provides that special meetings of the stockholders may be called only by the majority of our Board of Directors or the chairman of our Board of Directors, and only proposals included in our notice to stockholders may be considered at such special meetings.

Certain provisions in our amended and restated certificate of incorporation and amended and restated bylaws may be deemed to have an anti-takeover effect and may delay, deter or prevent a tender offer or takeover attempt that a stockholder might consider to be in its best interests, including attempts that might result in a premium being paid over the market price for the shares held by stockholders.

Our amended and restated certificate of incorporation contains provisions that permit our Board of Directors to issue, without any further vote or action by the stockholders, shares of preferred stock in one or more series and, with respect to each such series, to fix the number of shares constituting the series and the designation of the series, the dividend rates and whether such dividends will be cumulative or non-cumulative, the voting conversion or exchange rights of the shares of the series (if any), redemption rights, whether or not the shares of the series will be entitled to the benefit of a retirement or sinking fund, liquidation rights, the powers, preferences and relative, participation, optional and other special rights, if any, and any qualifications, limitations or restrictions, of the shares of such series. Please read "—Preferred Stock."

Our amended and restated certificate of incorporation and amended and restated bylaws provides that our Board of Directors is divided into three classes of directors, with the classes to be as nearly equal in number as possible, and the number of directors on our Board of Directors may be fixed only by the majority of our Board of Directors, as described above in "—Composition of Board of Directors; Election and Removal of Directors; Number of Directors."

At any time at least 33¹/3% of the voting power of all our shares is owned by the Apollo Funds and the Apollo Funds cast their votes associated with such shares in favor of the proposed action, our stockholders will be able to remove directors only by the affirmative vote of the holders of a majority of the voting power entitled to vote for the election of directors. At any other time, our stockholders will be able to remove directors only for cause and only by the affirmative vote of the holders of at least 66²/3% of the voting power entitled to vote for the election of directors. Vacancies on our Board of Directors may be filled only by a majority of our Board of Directors, although less than a quorum.

Our amended and restated certificate of incorporation provides that stockholders do not have the right to cumulative votes in the election of directors. Cumulative voting rights would have been available to the holders of our common stock if our amended and restated certificate of incorporation had not specifically provided that cumulative voting was not available.

Our amended and restated certificate of incorporation does not permit stockholder action without a meeting by consent if less than a majority of the voting power of all our shares is owned by the Apollo Funds. So long as the Apollo Funds own a majority of the voting power of all our shares, stockholder action without a meeting by consent is permitted without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, is signed by stockholders having not less than the minimum number of votes that would be necessary to authorize or take the action at a meeting at which all our shares were present and voted. Our amended and restated bylaws also provides that special meetings of the stockholders may be called only by a majority of our Board of Directors or the chairman of our Board of Directors, and only proposals included in our notice may be considered at such special meetings.

Our amended and restated bylaws provide that stockholders seeking to bring business before an annual meeting of stockholders, or to nominate candidates for election as directors at an annual meeting of stockholders, must provide timely notice thereof in writing. To be timely, a stockholder's notice generally will have to be delivered to and received at our principal executive offices not less than 60 days nor more than 120 days prior to the first anniversary of the preceding year's annual meeting; provided, that in the event that the date of such meeting is advanced more than 30 days prior to, or delayed by more than 30 days after, the anniversary of the preceding year's annual meeting of our stockholders, a stockholder's notice to be timely will have to be so delivered not earlier than the close of business on the 120th day prior to such meeting and not later than the close of business on the later of the 90th day prior to such meeting or, if the first public announcement of the date of such annual meeting is less than 100 days prior to such meeting, the tenth day following the day on which public announcement of the date of such meeting is first made. Our amended and restated bylaws also specify certain requirements as to the form and content of a stockholder's notice. These provisions may preclude stockholders from bringing matters before an annual meeting of stockholders or from making nominations for directors at an annual meeting of stockholders.

All the foregoing proposed provisions of our amended and restated certificate of incorporation and amended and restated bylaws could discourage potential acquisition proposals and could delay or prevent a change in control. These provisions are intended to enhance the likelihood of continuity and stability in the composition of our Board of Directors and in the policies formulated by our Board of Directors and to discourage certain types of transactions that may involve an actual or threatened change of control. These same provisions may delay, deter or prevent a tender offer or takeover attempt that a stockholder might consider to be in its best interest. In addition, such provisions could have the effect of discouraging others from making tender offers for our shares and, as a consequence, they also may inhibit fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts. Such provisions also may have the effect of preventing changes in our management.

Our amended and restated certificate of incorporation also provides that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of and to have consented to this forum selection provision. However, it is possible that a court could find our forum selection provision to be inapplicable or unenforceable.

We have elected to be exempt from the restrictions imposed under Section 203 of the DGCL. Section 203 of the DGCL provides that, subject to exceptions specified therein, an "interested stockholder" of a Delaware corporation shall not engage in any "business combination," including general mergers or consolidations or acquisitions of additional shares of the corporation, with the corporation for a three-year period following the time that such stockholder becomes an interested stockholder unless:

Under Section 203, the restrictions described above also do not apply to specified business combinations proposed by an interested stockholder following the announcement or notification of one of specified transactions involving the corporation and a person who had not been an interested stockholder during the previous three years or who became an interested stockholder with the approval of a majority of the corporation's directors, if such transaction is approved or not opposed by a majority of the directors who were directors prior to any person becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such directors by a majority of such directors.

Except as otherwise specified in Section 203, an "interested stockholder" is defined to include:

Under some circumstances, Section 203 makes it more difficult for a person who is an interested stockholder to effect various business combinations with us for a three-year period.

Under our amended and restated certificate of incorporation, to the extent permitted by law:

Our amended and restated certificate of incorporation provides that at any time the Apollo Funds control at least 33¹/3% of the voting power of our outstanding common stock, the amended and restated certificate of incorporation can be amended with the affirmative vote of a majority of the outstanding stock entitled to vote thereon or by the vote of a majority of our Board of Directors, so long as the Apollo Funds vote in favor of such amendment. At any other time, our amended and restated certificate of incorporation provides that the amended and restated certificate of incorporation can be amended by the affirmative vote of at least 66²/3% of the outstanding stock entitled to vote thereon or by the vote of a majority of our Board of Directors.

Our amended and restated certificate of incorporation provides that at any time the Apollo Funds control at least 33¹/3% of the voting power of our outstanding common stock, the amended and restated bylaws can be amended with the affirmative vote of a majority of the outstanding stock entitled to vote thereon, so long as the Apollo Funds vote in favor of such amendment, or by the vote of a majority of our Board of Directors. At any other time our amended and restated certificate of incorporation provides that the amended and restated bylaws can be amended by the affirmative vote of at least 66²/3% of the outstanding stock entitled to vote thereon or by the vote of a majority of our Board of Directors.

Our amended and restated certificate of incorporation limits the liability of our directors to the maximum extent permitted by Delaware law. Delaware law provides that directors will not be personally liable for monetary damages for breach of their fiduciary duties as directors, except with respect to liability:

However, if the DGCL is amended to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of our directors will be eliminated or limited to the fullest extent permitted by the DGCL, as so amended. The modification or repeal of this provision of our amended and restated certificate of incorporation will not adversely affect any right or protection of a director existing at the time of such modification or repeal.

Our amended and restated certificate of incorporation and amended and restated bylaws provide that we will, to the fullest extent from time to time permitted by law, indemnify our directors and officers against all liabilities and expenses in any suit or proceeding, arising out of their status as an officer or director or their activities in these capacities. We will also indemnify any person who, at our request, is or was serving as a director, officer, trustee, employee or agent of another corporation, partnership, joint venture, trust or other enterprise. We may, by action of our Board of Directors, provide indemnification to our employees and agents within the same scope and effect as the foregoing indemnification of directors and officers. In addition, we have entered into separate indemnification agreements with each of our directors and executive officers, which are broader than the specific indemnification provisions contained in the DGCL. These indemnification agreements require us, among other things, to indemnify our directors and officers against liabilities that may arise by reason of their status or service as directors or officers, other than liabilities arising from willful misconduct.

The right to be indemnified includes the right of an officer or a director to be paid expenses, including attorneys' fees, in advance of the final disposition of any proceeding, provided that, if required by law, we receive an undertaking to repay such amount if it will be determined that he or she is not entitled to be indemnified.

Our Board of Directors may take such action as it deems necessary to carry out these indemnification provisions, including adopting procedures for determining and enforcing indemnification rights and purchasing insurance policies. Our Board of Directors may also adopt bylaws, resolutions or contracts implementing indemnification arrangements as may be permitted by law. Neither the amendment nor the repeal of these indemnification provisions, nor the adoption of any provision of our amended and restated certificate of incorporation inconsistent with these indemnification provisions, will eliminate or reduce any rights to indemnification relating to such person's status or any activities prior to such amendment, repeal or adoption.

We believe these provisions will assist in attracting and retaining qualified individuals to serve as directors and officers.

The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Future sales of, or the perceived potential for the sale of, our common stock in the public market may have an adverse effect on the market price for our common stock and could impair our ability to raise capital through future sales of our securities. Please read "Risk Factors—Risks Related to this Offering and Our Common Stock—Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline."

As of February 6, 2014, we had 82,129,089 shares of our common stock outstanding. Of these shares, all 14,000,000 shares of common stock to be sold in this offering, in addition to the 18,137,895 shares that were sold in our initial public offering, will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our "affiliates" as such term is defined in Rule 144 of the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed "restricted securities" as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, 48,000,885 shares of our common stock held by the Apollo Funds (assuming the underwriters do not exercise their option to purchase additional shares of common stock) and our directors and executive officers will be available for sale in the public market upon the expiration of the lock-up agreements, beginning 90 days after the date of this prospectus and when permitted under Rule 144 or Rule 701. In addition, 2,145,409 shares of our common stock held by other employees will not be subject to a lock-up agreement and are eligible for sale in the public market, subject to any restrictions under Rule 144 or Rule 701.

In general, under Rule 144, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

In connection with our reorganization transactions, we exchanged Class B limited partner interests in Athlon Holdings LP held by members of our management team and certain employees for 10,151,522 shares of our common stock. Such shares became eligible for resale by the holders thereof on November 5, 2013 (90 days following the closing of our initial public offering), subject to the lock-up agreements discussed below.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of 1% of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

On August 20, 2013, we filed a registration statement on Form S-8 under the Securities Act to register 8,400,000 shares of common stock initially reserved for issuance under the Athlon Energy Inc. 2013 Incentive Award Plan. Shares registered under that registration statement are available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described below.

We have granted the Apollo Funds and certain members of our management team that hold New Holdings Units registration rights, in each case, with respect to an aggregate of 47,014,835 shares of outstanding common stock owned by them after the closing of this offering (assuming the underwriters do not exercise their option to purchase additional shares of common stock). Please read "Certain Relationships and Related Party Transactions—Stockholders Agreement" for more detail regarding these registration rights.

We entered into an exchange agreement with certain members of our management team and employees that hold an aggregate of 1,855,563 New Holdings Units after the closing of our initial public offering. Under the exchange agreement, each such holder (and certain permitted transferees thereof) may, under certain circumstances after the first anniversary of the closing of this offering, 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. A holder that receives shares of our common stock upon exchange of its New Holdings Units will be eligible to sell its shares subject to Rule 144, subject to any applicable lock-up agreements discussed below.

We, the Apollo Funds and each of our directors and executive officers have agreed that, subject to certain exceptions, without the prior written consent of Citigroup Global Markets Inc., we and they will not, directly or indirectly, for a period of 90 days after the date of the offering, offer, pledge, sell, contract to sell or otherwise transfer or dispose of any shares of our common stock (other than the shares sold by the Apollo Funds in this offering) or any other securities convertible into or exercisable or exchangeable for our common stock. For additional information, please read "Underwriting (Conflicts of Interest)."

The following discussion is a summary of the material U.S. federal income tax consequences to non-U.S. holders (as defined below) of the purchase, ownership and disposition of our common stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or foreign tax laws are not discussed. This discussion is based on the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations promulgated thereunder, judicial decisions and published rulings and administrative pronouncements of the U.S. Internal Revenue Service ("IRS"), in each case in effect as of the date of this offering. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect a non-U.S. holder of our common stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position regarding the tax consequences of the purchase, ownership and disposition of our common stock.

This discussion is limited to non-U.S. holders that hold our common stock as a "capital asset" within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a non-U.S. holder's particular circumstances, including the impact of the tax on net investment income imposed by Section 1411 of the Code. In addition, it does not address consequences relevant to non-U.S. holders subject to particular rules, including, without limitation:

If a partnership (or other entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our common stock and the partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.

THIS DISCUSSION IS FOR INFORMATION PURPOSES ONLY AND IS NOT INTENDED AS TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR

SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

For purposes of this discussion, a "non-U.S. holder" is any beneficial owner of our common stock that is neither a "U.S. person" nor an entity treated as a partnership for United States federal income tax purposes. A U.S. person is any person that, for U.S. federal tax purposes, is or is treated as any of the following:

We do not anticipate declaring or paying dividends to holders of our common stock in the foreseeable future. However, if we make distributions on our common stock, such distributions of cash or property on our common stock will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce a non-U.S. holder's adjusted tax basis in its common stock, but not below zero. Any excess will be treated as capital gain and will be treated as described below in the section relating to the sale or disposition of our common stock.

Subject to the discussion below on backup withholding and foreign accounts, dividends paid to a non-U.S. holder of our common stock that are not effectively connected with the non-U.S. holder's conduct of a trade or business within the United States will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty).

Non-U.S. holders may be entitled to a reduction in or an exemption from withholding on dividends as a result of either (a) an applicable income tax treaty or (b) the non-U.S. holder holding our common stock in connection with the conduct of a trade or business within the United States and dividends being paid in connection with that trade or business. To claim such a reduction in or exemption from withholding, the non-U.S. holder must provide the applicable withholding agent with a properly executed (a) IRS Form W-8BEN claiming an exemption from or reduction of the withholding tax under the benefit of an income tax treaty between the United States and the country in which the non-U.S. holder resides or is established, or (b) IRS Form W-8ECI stating that the dividends are not subject to withholding tax because they are effectively connected with the conduct by the non-U.S. holder of a trade or business within the United States, as may be applicable. These certifications must be provided to the applicable withholding agent prior to the payment of dividends and must be updated periodically. Non-U.S. holders that do not timely provide the applicable withholding agent with the required certification, but that qualify for a reduced rate under an applicable income tax treaty, may

obtain a refund of any excess amounts withheld under these rules by timely filing an appropriate claim for refund with the IRS.

Subject to the discussion below on backup withholding and foreign accounts, if dividends paid to a non-U.S. holder are effectively connected with the non-U.S. holder's conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the non-U.S. holder maintains a permanent establishment in the United States to which such dividends are attributable), then, although exempt from U.S. federal withholding tax (provided the non-U.S. holder provides appropriate certification, as described above), the non-U.S. holder will be subject to U.S. federal income tax on such dividends on a net income basis at the regular graduated U.S. federal income tax rates. In addition, a non-U.S. holder that is a corporation may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits for the taxable year that are attributable to such dividends (and, if required by an applicable income tax treaty, that are attributable to a permanent establishment maintained by the corporate non-U.S. holder in the United States), as adjusted for certain items. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

Subject to the discussions below on backup withholding and foreign accounts, a non-U.S. holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

Gain described in the first bullet point above will generally be subject to U.S. federal income tax on a net income basis at the regular graduated U.S. federal income tax rates. A non-U.S. holder that is a foreign corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) of a portion of its effectively connected earnings and profits for the taxable year, as adjusted for certain items.

A non-U.S. holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on any gain derived from the disposition, which may be offset by certain U.S. source capital losses of the non-U.S. holder (even though the individual is not considered a resident of the United States) provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses.

With respect to the third bullet point above, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, so long as our common stock is "regularly traded on an established securities market," a non-U.S. holder will be subject to U.S. federal net income tax on a disposition of our common stock only if the non-U.S. holder actually or constructively holds or held (at any time during the shorter of the five-year period preceding the date of disposition or the holder's holding period) more than 5% of our common stock. If our common stock is not considered to be so traded, all non-U.S. holders would be subject to U.S. federal net income tax on disposition of our common stock and a 10% withholding tax would apply to the gross proceeds from the sale of our common stock by a non-U.S. holder.

Non-U.S. holders should consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.

A non-U.S. holder will not be subject to backup withholding with respect to payments of dividends on our common stock we make to the non-U.S. holder, provided the applicable withholding agent does not have actual knowledge or reason to know such holder is a United States person and the holder certifies its non-U.S. status, such as by providing a valid IRS Form W-8BEN or W-8ECI, or other applicable certification. However, information returns will be filed with the IRS in connection with any dividends on our common stock paid to the non-U.S. holder, regardless of whether any tax was actually withheld. Copies of these information returns may also be made available under the provisions of a specific treaty or agreement to the tax authorities of the country in which the non-U.S. holder resides or is established.

Information reporting and backup withholding may apply to the proceeds of a sale of our common stock within the United States, and information reporting may (although backup withholding generally will not) apply to the proceeds of a sale of our common stock outside the United States conducted through certain U.S.- related financial intermediaries, in each case, unless the beneficial owner certifies under penalty of perjury that it is a non-U.S. holder on IRS Form W-8BEN or other applicable form (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person) or such owner otherwise establishes an exemption.

Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the county in which the non-U.S. holder resides or is established.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-U.S. holder's U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Withholding taxes may be imposed under the Foreign Account Tax Compliance Act ("FATCA") on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our common stock paid to a "foreign financial institution" or a "non-financial foreign entity" (each as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any "substantial United States owners" (as defined in the Code) or furnishes identifying information regarding each substantial United States owner or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain "specified United States persons" or "United States-owned foreign entities" (each as defined in the Code), annually report certain information about such accounts and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Under the applicable Treasury Regulations, withholding under FATCA generally will apply to payments of dividends on our common stock made on or after July 1, 2014 and to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2017.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our common stock.

Citigroup Global Markets Inc. and Goldman, Sachs & Co. are acting as the representatives of the underwriters and Citigroup Global Markets Inc., Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith, Incorporated, Barclays Capital Inc., RBC Capital Markets, LLC, Tudor, Pickering, Holt & Co. Securities, Inc., UBS Securities LLC and Wells Fargo Securities, LLC are the joint book-running managers of this offering. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and the selling stockholders have agreed to sell to that underwriter, the number of shares set forth opposite the underwriter's name.

Underwriter		Number of Shares

Citigroup Global Markets Inc.			4,200,000
Goldman, Sachs & Co.			3,850,000
Merrill Lynch, Pierce, Fenner & Smith, Incorporated			630,000
Barclays Capital Inc.			630,000
RBC Capital Markets, LLC			630,000
Tudor, Pickering, Holt & Co. Securities, Inc.			630,000
UBS Securities LLC			630,000
Wells Fargo Securities, LLC			630,000
Apollo Global Securities, LLC			1,120,000
Scotia Capital (USA) Inc.			280,000
Simmons & Company International			210,000
Stephens Inc.			210,000
CIBC World Markets Corp.			140,000
Mitsubishi UFJ Securities (USA), Inc.			140,000
Academy Securities, Inc.			35,000
KLR Group, LLC			35,000

Total			14,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase the shares included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the underwriters' option to purchase additional shares described below) if they purchase any of the shares.

Shares sold by the underwriters to the public will initially be offered at the public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount from the public offering price not to exceed $0.77 per share. After the shares are released for sale to the public, if all the shares are not sold at the offering price following a bona fide effort to do so, the underwriters may change the offering price and the other selling terms.

If the underwriters sell more shares than the total number set forth in the table above, the Apollo Funds have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 2,100,000 additional shares at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase a number of additional shares approximately proportionate to that underwriter's initial purchase commitment. Any shares issued or sold under the option will be issued and sold on the same terms and conditions as the other shares that are the subject of this offering.

We, our officers and directors and the Apollo Funds have agreed that, for a period of 90 days from the date of this prospectus, subject to certain exceptions, we and they will not, without the prior

written consent of Citigroup Global Markets Inc., dispose of or hedge any shares or any securities convertible into or exchangeable for our common stock. Citigroup Global Markets Inc. in its sole discretion may release any of the securities subject to these lock-up agreements at any time which, in the case of officers and directors, shall be with notice.

We have agreed to pay expenses incurred by the selling stockholders in connection with the offering, other than the underwriting discounts and commissions. The following table shows the underwriting discounts and commissions that the Apollo Funds as selling stockholders are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares.

We have agreed to reimburse the underwriters for certain of their expenses in an amount up to $20,000.

In connection with the offering, the underwriters may purchase and sell shares in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters' option to purchase additional shares, and stabilizing purchases.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the shares. They may also cause the price of the shares to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may

conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us and the selling stockholders from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates including the Apollo Funds.

In addition, affiliates of certain of the underwriters are lenders under our credit agreement and/or are holders of our senior notes. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. Typically, such underwriters or their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities. Certain of the underwriters or their affiliates were underwriters in connection with our initial public offering and were initial purchasers in our senior notes offering and received customary fees and reimbursement of expenses. In connection therewith, Apollo Global Securities, LLC, an affiliate of the Apollo Funds, was an underwriter in connection with our initial public offering and was an initial purchaser in our senior notes offering and received a portion of the gross spread of approximately $1.4 million. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Apollo Global Securities, LLC is an affiliate of the Apollo Funds. Since the Apollo Funds beneficially own 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, the Apollo Funds, as selling stockholders, will receive more than 5% of the net proceeds of this offering and a "conflict of interest" will also exist 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.

Prior to our initial public offering, we were a party to a Transaction Fee Agreement and a Services Agreement with Apollo, both of which were entered into on August 23, 2010. In October 2012, Apollo assigned its rights and obligations under the Transaction Fee Agreement to one of its affiliates, Apollo Global Securities, LLC. Since our inception through the termination of the Transaction Fee Agreement, we incurred transaction fees under the Transaction Fee Agreement of approximately $7.5 million in total. During 2013 until the termination of the Services Agreement and during 2012 and 2011, we incurred approximately $500,000, $493,000 and $411,000, respectively, of advisory fees under the

Services Agreement. Upon the consummation of our initial public offering, we terminated the Transaction Fee Agreement and the Services Agreement. In connection with the termination of the Services Agreement, we paid Apollo $2.4 million (plus $132,000 of unreimbursed fees). Such payment corresponds 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) using a discount rate of 8.0%. No termination fee was paid in connection with the termination of the Transaction Fee Agreement.

We and the Apollo Funds as selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of shares described in this prospectus may not be made to the public in that relevant member state other than:

provided that no such offer of shares shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an "offer of securities to the public" in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe for the shares, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state) and includes any relevant implementing measure in the relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

The sellers of the shares have not authorized and do not authorize the making of any offer of shares through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the shares as contemplated in this prospectus. Accordingly, no purchaser of the shares, other than the underwriters, is authorized to make any further offer of the shares on behalf of the sellers or the underwriters.

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the "Order") or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a "relevant person"). This prospectus and its contents are

confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

Neither this prospectus nor any other offering material relating to the shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the shares has been or will be:

The shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier.

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a "prospectus" within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

The shares offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan

(including any corporation or other entity organized under the laws of Japan), except (i) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (ii) in compliance with any other applicable requirements of Japanese law.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA"), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

shares, debentures and units of shares and debentures of that corporation or the beneficiaries' rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission, in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the "Corporations Act"), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the shares may only be made to persons (the "Exempt Investors") who are "sophisticated investors" (within the meaning of section 708(8) of the Corporations Act), "professional investors" (within the meaning of section 708(11) of the Corporations Act) or otherwise

pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the shares without disclosure to investors under Chapter 6D of the Corporations Act.

The shares applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring shares must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority ("DFSA"). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

We have not and will not register with the Swiss Financial Market Supervisory Authority ("FINMA") as a foreign collective investment scheme pursuant to Article 119 of the Federal Act on Collective Investment Scheme of 23 June 2006, as amended ("CISA"), and accordingly the securities being offered pursuant to this prospectus have not and will not be approved, and may not be licenseable, with FINMA. Therefore, the securities have not been authorized for distribution by FINMA as a foreign collective investment scheme pursuant to Article 119 CISA and the securities offered hereby may not be offered to the public (as this term is defined in Article 3 CISA) in or from Switzerland. The securities may solely be offered to "qualified investors," as this term is defined in Article 10 CISA, and in the circumstances set out in Article 3 of the Ordinance on Collective Investment Scheme of 22 November 2006, as amended ("CISO"), such that there is no public offer. Investors, however, do not benefit from protection under CISA or CISO or supervision by FINMA. This prospectus and any other materials relating to the securities are strictly personal and confidential to each offeree and do not constitute an offer to any other person. This prospectus may only be used by those qualified investors to whom it has been handed out in connection with the offer described herein and may neither directly or indirectly be distributed or made available to any person or entity other than its recipients. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in Switzerland or from Switzerland. This prospectus does not constitute an issue prospectus as that term is understood pursuant to Article 652a and/or 1156 of the Swiss Federal Code of Obligations. We have not applied for a listing of the securities on the SIX Swiss Exchange or any other regulated securities market in Switzerland, and consequently, the information presented in this prospectus does not necessarily comply with the information standards set out in the listing rules of the SIX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SIX Swiss Exchange.

The validity of our common stock offered by this prospectus will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

The consolidated financial statements of Athlon Energy Inc. at December 31, 2012 and 2011, and for each of the two years in the period ended December 31, 2012, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The carve out financial statements of the Element Petroleum, LP Permian Basin Operations as of and for the nine months ended September 30, 2011 included in the registration statement of which this prospectus is a part, have been audited by UHY LLP, an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value as of December 31, 2012 and 2011 is based on proved reserve reports prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum engineers. These estimates are included in this prospectus in reliance upon the authority of such firm as an expert in these matters.

We are required to file annual and quarterly reports and other information with the SEC. You may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C., 20549. Please call 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Our filings will also be available to the public from commercial document retrieval services and at the web site maintained by the SEC at http://www.sec.gov. Our reports and other information that we have filed, or may in the future file, with the SEC are not incorporated by reference into and do not constitute part of this prospectus.

We have filed with the SEC a registration statement under the Securities Act with respect to the shares of our common stock offered by this prospectus. This prospectus, filed as part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules thereto as permitted by the rules and regulations of the SEC. For further information about us and our common stock, you should refer to the registration statement. This prospectus summarizes provisions that we consider material of certain contracts and other documents to which we refer you. Because the summaries may not contain all of the information that you may find important, you should review the full text of those documents.

We have not authorized anyone to give you any information or to make any representations about us or the transactions we discuss in this prospectus other than those contained in this prospectus. If you are given any information or representations about these matters that is not discussed in this prospectus, you must not rely on that information. This prospectus is not an offer to sell or a solicitation of an offer to buy securities anywhere or to anyone where or to whom we are not permitted to offer or sell securities under applicable law.

"3-D seismic." Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

"Basin." A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

"Bbl." One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

"BOE." One barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

"British thermal unit (Btu)." The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

"Cash operating expense." Equals lease operating expense plus production, severance and ad valorem tax, processing, gathering and overhead and general and administrative expense less non-cash equity-based compensation expense and acquisition costs.

"Completion." The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

"Condensate." A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

"Developed acreage." The number of acres that are allocated or assignable to productive wells or wells capable of production.

"Development capital." Expenditures to obtain access to proved reserves and to construct facilities for producing, treating and storing hydrocarbons.

"Development well." A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

"Dry hole." A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

"Economically producible." A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC's Regulation S-X, Rule 4-10(a)(10).

"Enhanced recovery." The recovery of hydrocarbons through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

"Estimated ultimate recovery (EUR)." The sum of gross reserves remaining as of a given date and cumulative production as of that date.

"Exploratory well." A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

"Finding and Development (F&D) costs." F&D costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year, by the sum of proved reserve extensions, discoveries, acquisitions and revisions for the year.

"Field." An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC's Regulation S-X, Rule 4-10(a)(15).

"Formation." A layer of rock which has distinct characteristics that differ from nearby rock.

"Gross acres" or "Gross wells." The total acres or wells, as the case may be, in which an entity owns a working interest.

"Held by production acreage." Acreage covered by a mineral lease that perpetuates a company's right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

"Horizontal drilling." A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

"Infill wells." Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

"Lease operating expense (LOE)." All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

"Natural gas liquids (NGLs)." The combination of ethane, propane, butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

"Net acres" or "Net wells." The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells. For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

"Net revenue interest." An owner's interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

"Operator." The entity responsible for the exploration, development and production of a well or lease.

"Present value of future net revenues (PV-10)." The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

"Productive well." A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

"Proved developed reserves." Proved reserves that can be expected to be recovered:

"Proved reserves." Those 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, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC's Regulation S-X, Rule 4-10(a)(22).

"Proved undeveloped reserves (PUDs)." Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

"Reasonable certainty." A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC's Regulation S-X, Rule 4-10(a)(24).

"Recompletion." The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

"Reliable technology." A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

"Reserve/production ratio (R/P Ratio)." The number of years proved reserves would last assuming current production continued at the January 2013 rate. This ratio is calculated by dividing annualized average daily production into the proved reserve quantity. Because production rates naturally decline over time, the R/P Ratio is not a useful estimate of how long properties should economically produce.

"Reserves." Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

"Reservoir." A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

"Royalty." An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

"Spacing." The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

"Stacked pay." Multiple geological zones that potentially contain hydrocarbons and are arranged in a vertical stack.

"Standardized Measure." The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using 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 and costs in effect as of the date of estimation), less future development and production costs and income taxes, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized Measure does not give effect to derivative transactions.

"Undeveloped acreage." Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

"Wellbore." The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

"Working interest." The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

"WTI." West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

ATHLON ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and par value amounts)

	September 30, 2013			December 31, 2012

	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	196,888		$	8,871
Accounts receivable		45,851			24,501
Derivatives, at fair value		—			2,246
Inventory		972			1,022
Other		1,205			2,486

Total current assets		244,916			39,126

Properties and equipment, at cost—full cost method:
Proved properties, including wells and related equipment		1,084,881			788,571
Unproved properties		110,095			89,860
Accumulated depletion, depreciation, and amortization		(135,689	)		(73,824	)

		1,059,287			804,607

Derivatives, at fair value		1,211			2,854
Debt issuance costs		14,603			4,418
Other		1,400			1,293

Total assets	$	1,321,417		$	852,298

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,338		$	3,170
Affiliate		2			935
Accrued liabilities:
Lease operating		5,391			3,858
Production, severance, and ad valorem taxes		5,362			1,307
Development capital		60,092			39,483
Interest		16,802			834
Derivatives, at fair value		10,185			592
Revenue payable		19,550			9,330
Deferred taxes		14,529			58
Other		2,021			1,808

Total current liabilities		136,272			61,375
Derivatives, at fair value		992			519
Asset retirement obligations, net of current portion		6,439			5,049
Long-term debt		500,000			362,000
Deferred taxes		67,878			2,340
Other		109			138

Total liabilities		711,690			431,421

Commitments and contingencies
Equity:
Partners' equity		—			420,877
Preferred stock, $.01 par value, at September 30, 2013, 50,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, at September 30, 2013, 500,000,000 shares authorized, 82,129,089 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			420,877

Total liabilities and equity	$	1,321,417		$	852,298

The accompanying notes are an integral part of these consolidated financial statements.

ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

(unaudited)

	Three months ended September 30,						Nine months ended September 30,

	2013			2012			2013			2012
Revenues:
Oil	$	75,666		$	34,357		$	175,934		$	91,407
Natural gas		4,164			2,383			11,894			5,323
Natural gas liquids		8,595			5,346			20,508			14,379

Total revenues		88,425			42,086			208,336			111,109

Expenses:
Production:
Lease operating		8,762			7,205			23,774			17,846
Production, severance, and ad valorem taxes		5,439			2,806			13,380			7,617
Processing, gathering, and overhead		59			29			169			55
Depletion, depreciation, and amortization		23,611			15,091			62,022			37,770
General and administrative		6,725			2,134			13,723			7,212
Contract termination fee		2,408			—			2,408			—
Derivative fair value loss (gain)		27,037			14,268			21,331			(9,590	)
Accretion of discount on asset retirement obligations		174			123			485			343

Total expenses		74,215			41,656			137,292			61,253

Operating income		14,210			430			71,044			49,856

Other income (expenses):
Interest		(10,039	)		(2,602	)		(26,595	)		(5,804	)
Other		30			—			30			2

Total other expenses		(10,009	)		(2,602	)		(26,565	)		(5,802	)

Income (loss) before income taxes		4,201			(2,172	)		44,479			44,054
Income tax provision (benefit)		1,934			(76	)		6,805			1,546

Consolidated net income (loss)		2,267			(2,096	)		37,674			42,508
Less: net income (loss) attributable to noncontrolling interest		(215	)		—			616			—

Net income (loss) attributable to stockholders	$	2,482		$	(2,096	)	$	37,058		$	42,508

Net income (loss) per common share:
Basic	$	0.03		$	(0.03	)	$	0.53		$	0.64
Diluted	$	0.03		$	(0.03	)	$	0.53		$	0.62
Weighted average common shares outstanding:
Basic		76,637			66,340			69,810			66,340
Diluted		78,493			66,340			71,666			68,196

The accompanying notes are an integral part of these consolidated financial statements.

ATHLON ENERGY INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)

				Athlon Stockholders

	Partners' Equity			Issued Shares of Common Stock		Common Stock		Additional Paid-in Capital			Retained Earnings		Total Stockholders' Equity			Noncontrolling Interest		Total Equity
Balance at December 31, 2012	$	420,877			—	$	—	$	—		$	—	$	—		$	—	$	420,877
Capital contributions		1,500			—		—		—			—		—			—		1,500
Equity-based compensation prior to corporate reorganization		89			—		—		—			—		—			—		89
Net income prior to corporate reorganization		26,780			—		—		—			—		—			—		26,780
Distributions to Athlon Holdings LP's Class A limited partners		(75,000	)		—		—		—			—		—			—		(75,000	)
Common stock issued in corporate reorganization		(374,246	)		66,340		663		364,154			—		364,817			9,429		—
Tax impact of corporate reorganization		—			—		—		(73,204	)		—		(73,204	)		—		(73,204	)
Equity-based compensation subsequent to corporate reorganization		—			—		—		2,160			—		2,160			—		2,160
Shares of common stock sold in initial public offering, net of offering costs		—			15,789		158		295,473			—		295,631			—		295,631
Consolidated net income subsequent to corporate reorganization		—			—		—		—			10,278		10,278			616		10,894

Balance at September 30, 2013	$	—			82,129	$	821	$	588,583		$	10,278	$	599,682		$	10,045	$	609,727

The accompanying notes are an integral part of these consolidated financial statements.

ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine months ended September 30,

	2013			2012
Cash flows from operating activities:
Consolidated net income	$	37,674		$	42,508
Adjustments to reconcile consolidated net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		62,022			37,770
Deferred taxes		6,805			1,546
Non-cash derivative loss (gain)		13,955			(11,760	)
Equity-based compensation		1,799			118
Other		4,756			952
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(21,350	)		(7,390	)
Other current assets		(155	)		(975	)
Accounts payable		(702	)		(461	)
Accrued interest		15,968			478
Revenue payable		9,718			3,317
Other current liabilities		6,285			(3,349	)

Net cash provided by operating activities		136,775			62,754

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(36,533	)		(3,290	)
Development of oil and natural gas properties		(257,984	)		(183,327	)
Other		(486	)		(283	)

Net cash used in investing activities		(295,003	)		(186,900	)

Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		629,627			425,684
Payments on long-term debt		(505,926	)		(325,000	)
Distributions to Athlon Holdings LP's Class A limited partners		(75,000	)		—
Shares of common stock sold in initial public offering, net of offering costs		296,044			—
Other		1,500			166

Net cash provided by financing activities		346,245			100,850

Increase (decrease) in cash and cash equivalents		188,017			(23,296	)
Cash and cash equivalents, beginning of period		8,871			32,030

Cash and cash equivalents, end of period	$	196,888		$	8,734

The accompanying notes are an integral part of these consolidated financial statements.

Athlon Energy Inc. (together with its subsidiaries, "Athlon"), a Delaware corporation, was formed on April 1, 2013 and is 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.

On April 26, 2013, Athlon Holdings LP (together with its subsidiaries, "Holdings"), a Delaware limited partnership, underwent a corporate reorganization and as a result, Holdings became a majority-owned subsidiary of Athlon. Holdings is considered Athlon's accounting predecessor. Athlon operates and controls all of the business and affairs of Holdings and consolidates its financial results. Holdings is not subject to federal income taxes. On the date of the corporate reorganization, a corresponding "first day" net deferred tax liability of approximately $73.2 million was recorded for differences between the tax and book basis of Athlon's assets and liabilities. The offset of the deferred tax liability was recorded to additional paid-in capital.

Prior to the corporate reorganization, Holdings was a party to a limited partnership agreement with its management group and Apollo Athlon Holdings, LP ("Apollo"), which is an affiliate of Apollo Global Management, LLC. Prior to the corporate reorganization, Apollo Investment Fund VII, L.P. and its parallel funds (the "Apollo Funds"), members of Holdings' management team, and certain employees owned all of the Class A limited partner interests in Holdings and members of Holdings' management team and certain employees owned all of the Class B limited partner interests in Holdings.

In the corporate 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 Holdings for common stock of Athlon. The remaining holders of Class A limited partner interests in Holdings have not exchanged their interests in the reorganization transactions. In addition, the holders of the Class B limited partner interests in Holdings exchanged their interests for common stock of Athlon subject to the same conditions and vesting terms.

On August 7, 2013, Athlon completed its initial public offering ("IPO") of 15,789,474 shares of its 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 Holdings was amended and restated to, among other things, modify Holdings' 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 that held Class A limited partner interests now own 1,855,563 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 common stock of Athlon 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. Athlon used the net proceeds from the IPO to purchase New Holdings Units from Holdings. Holdings used the proceeds it received as a result of Athlon's purchase of New Holdings Units (i) to reduce outstanding borrowings under its credit agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes, including potential acquisitions.

Athlon's consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, Athlon's financial position as of September 30, 2013, results of operations for the three and nine months ended September 30, 2013 and 2012, and cash flows for the nine months ended September 30, 2013 and 2012. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

Certain amounts and disclosures have been condensed and omitted from the unaudited consolidated financial statements pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). Therefore, these unaudited consolidated financial statements should be read in conjunction with Holdings' audited consolidated financial statements and related notes thereto included in Athlon's final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on August 5, 2013.

Athlon accounts 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.

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

In April 2013, Athlon had a corporate reorganization to effectuate its IPO. Holdings, Athlon's accounting predecessor, is a partnership not subject to federal income tax. Pursuant to the steps of the corporate reorganization, certain Class A limited partners and the Class B limited partners of Holdings exchanged their interests for shares of Athlon's common stock. Athlon's 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 the accompanying consolidated financial statements.

As of September 30, 2013, management and employees owned approximately 2.2% of Holdings. Athlon owns 100% of Athlon Holdings GP LLC, which is Holdings' general partner. Considering the presumption of control, Athlon has fully consolidated the financial position, results of operations, and cash flows of Holdings.

As presented in the accompanying Consolidated Balance Sheets, "Noncontrolling interest" as of September 30, 2013 of approximately $10.0 million represents management and employees' 1,855,563 New Holdings Units that are exchangeable for shares of Athlon's common stock on a one-for-one basis. As presented in the accompanying Consolidated Statements of Operations, "Net income (loss) attributable to noncontrolling interest" for the three and nine months ended September 30, 2013 of approximately $(0.2) million and $0.6 million, respectively, represents the net income of Holdings attributable to management and employees since April 26, 2013.

The following table summarizes the effects of changes in Athlon's partnership interest in Holdings on Athlon's equity for the periods indicated:

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update ("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 setoff and related arrangements associated with its derivative instruments, repurchase agreements, and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements are required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs were effective

retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs did not impact Athlon's financial position, results of operations, or liquidity.

No other new accounting pronouncements issued or effective from January 1, 2013 through the date of this Report, had or are expected to have a material impact on Athlon's unaudited consolidated financial statements.

Amounts shown in the accompanying Consolidated Balance Sheets as "Proved properties, including wells and related equipment" consisted of the following as of the dates indicated:

The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the accompanying Consolidated Balance Sheets. As of September 30, 2013, the fair value of the senior notes was approximately $515.6 million using open market quotes ("Level 1" input).

Athlon uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil production. These arrangements are structured to reduce Athlon's exposure to commodity price decreases, but they can also limit the benefit Athlon might otherwise receive from commodity price increases. Athlon's risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions, most of which are lenders underwriting Holdings' credit agreement.

Athlon applies the provisions of the "Derivatives and Hedging" topic of the Accounting Standards Codification, which requires each derivative instrument to be recorded in the accompanying Consolidated Balance Sheets 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. Athlon elected not to designate its current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in "Derivative fair value loss (gain)" in the accompanying Consolidated Statements of Operations.

Athlon enters into commodity derivative contracts for the purpose of economically fixing the price of its anticipated oil production even though Athlon does not designate the derivatives as hedges for accounting purposes. Athlon classifies 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 Athlon's oil and natural gas operations, they are classified as cash flows from operating activities in the accompanying Consolidated Statements of Cash Flows.

Commodity prices are often subject to significant volatility due to many factors that are beyond Athlon's 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. Athlon manages 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.

The following table summarizes Athlon's open commodity derivative contracts as of September 30, 2013:

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

Counterparty Risk. At September 30, 2013, Athlon had committed 10% or greater (in terms of fair market value) of its oil derivative contracts in asset positions from the following counterparties, or their affiliates:

Athlon does not require collateral from its counterparties for entering into financial instruments, so in order to mitigate the credit risk associated with financial instruments, Athlon enters into master netting agreements with its counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and Athlon. Instead of treating each financial transaction between the counterparty and Athlon separately, the master netting agreement enables the counterparty and Athlon to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit Athlon in two ways: (i) default by a counterparty under a single financial trade can trigger rights to terminate all financial trades with such counterparty; and (ii) netting of settlement amounts reduces Athlon's credit exposure to a given counterparty in the event of close-out. Athlon's accounting policy is to not offset fair value amounts between different counterparties for derivative instruments in the accompanying Consolidated Balance Sheets.

The following table summarizes the fair value of Athlon's derivative instruments not designated as hedging instruments as of the dates indicated:

Balance Sheet Location	Oil Commodity Derivatives			Commodity Derivatives Netting(a)			Total Commodity Derivatives

	(in thousands)
*As of September 30, 2013*
Assets
Derivatives—current	$	162		$	(162	)	$	—
Derivatives—noncurrent		2,149			(938	)		1,211

Total assets		2,311			(1,100	)		1,211

Liabilities
Derivatives—current		(10,347	)		162			(10,185	)
Derivatives—noncurrent		(1,930	)		938			(992	)

Total liabilities		(12,277	)		1,100			(11,177	)

Net liabilities	$	(9,966	)	$	—		$	(9,966	)

*As of December 31, 2012*
Assets
Derivatives—current	$	3,386		$	(1,140	)	$	2,246
Derivatives—noncurrent		3,265			(411	)		2,854

Total assets		6,651			(1,551	)		5,100

Liabilities
Derivatives—current		(1,732	)		1,140			(592	)
Derivatives—noncurrent		(930	)		411			(519	)

Total liabilities		(2,662	)		1,551			(1,111	)

Net assets	$	3,989		$	—		$	3,989

The following table summarizes the effect of derivative instruments not designated as hedges on the accompanying Consolidated Statements of Operations for the periods indicated (in thousands):

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting principles generally accepted in the United States ("GAAP") establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are defined as follows:

As required by GAAP, Athlon utilizes 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. Athlon's 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 and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of Athlon's assets and liabilities that are accounted for at fair value on a recurring basis:

Athlon adjusts the valuations from the valuation model for nonperformance risk. For commodity derivative contracts which are in an asset position, Athlon adds the counterparty's credit default swap spread to the risk-free rate. If a counterparty does not have a credit default swap spread, Athlon uses other companies with similar credit ratings to determine the applicable spread. For commodity derivative contracts which are in a liability position, Athlon uses the yield on its senior notes less the risk-free rate. All fair values have been adjusted for nonperformance risk resulting in a decrease in the net commodity derivative liability of approximately $136,000 as of September 30, 2013 and an increase in the net commodity derivative asset of approximately $125,000 as of December 31, 2012.

The following table sets forth Athlon's assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated:

				Fair Value Measurements at Reporting Date Using

Description	Asset (liability), net			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(in thousands)
As of September 30, 2013
Oil derivative contracts—swaps	$	(9,622	)	$	—	$	(9,622	)	$	—
Oil derivative contracts—basis differential swaps		(330	)		—		(330	)		—
Oil derivative contracts—collars		(14	)		—		(14	)		—

Total	$	(9,966	)	$	—	$	(9,966	)	$	—

As of December 31, 2012
Oil derivative contracts—swaps	$	4,069		$	—	$	4,069		$	—
Oil derivative contracts—collars		(80	)		—		(80	)		—

Total	$	3,989		$	—	$	3,989		$	—

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in Athlon's asset retirement obligations for the nine months ended September 30, 2013 (in thousands):

In April 2013, Holdings issued $500 million aggregate principal amount of 7³/8% senior notes due 2021 (the "Notes"). The net proceeds from the Notes were used to repay a portion of the outstanding borrowings under Holdings' credit agreement, to repay in full and terminate Holdings' former second lien term loan, to make a $75 million distribution to Holdings' Class A limited partners, and for general partnership purposes. On August 14, 2013, Holdings entered into a supplemental indenture pursuant to which Athlon became an unconditional guarantor of the Notes.

The indenture governing the Notes contains covenants, including, among other things, covenants that restrict Holdings' ability to:

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, Holdings will be able to redeem some or all of the Notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption. Prior to April 15, 2016, Holdings will be able, at its option, to redeem up to 35% of the aggregate principal amount of the 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 Holdings' option, prior to April 15, 2016, Holdings may redeem some

or all of the Notes at a redemption price equal to 100% of the principal amount of the 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, Holdings 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 Holdings 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 Notes is payable in cash semi-annually in arrears, commencing on October 15, 2013, through maturity.

As a result of the issuance of the Notes, Holdings' former second lien term loan was paid off and retired and the borrowing base of the credit agreement was reduced resulting in a write off of unamortized debt issuance costs of approximately $2.8 million, which is included in "Interest expense" in the accompanying Consolidated Statements of Operations and "Other" in the operating activities section of the accompanying Consolidated Statements of Cash Flows for the nine months ended September 30, 2013.

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

In conjunction with the offering of the Notes in April 2013 as discussed above, the borrowing base under the Holdings Credit Agreement was reduced to $267.5 million. In May 2013, Holdings amended the Holdings Credit Agreement to, among other things, increase the borrowing base to $320 million. As of September 30, 2013, the borrowing base was $320 million and there were no outstanding borrowings and no outstanding letters of credit under the Holdings Credit Agreement. Please see "Note 12. Subsequent Events" for discussion of Athlon's borrowing base redetermination.

Obligations under the Holdings Credit Agreement are secured by a first-priority security interest in substantially all of Holdings' proved reserves and in the equity interests of its operating subsidiaries. In addition, obligations under the Holdings Credit Agreement are guaranteed by Athlon and Holdings' operating subsidiaries.

Loans under the Holdings Credit Agreement are subject to varying rates of interest based on (i) outstanding borrowings in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the Holdings Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Holdings Credit Agreement bear interest at the base rate plus the applicable margin indicated in

the following table. Holdings also incurs a quarterly commitment fee on the unused portion of the Holdings Credit Agreement indicated in the following table:

The "Eurodollar rate" for any interest period (either one, two, three, or nine months, as selected by Holdings) is the rate equal to the British Bankers Association London Interbank Offered Rate ("LIBOR") for deposits in dollars for a similar interest period. The "Base Rate" is calculated as the highest of: (i) the annual rate of interest announced by Bank of America, N.A. as its "prime rate"; (ii) the federal funds effective rate plus 0.5%; or (iii) 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 the Holdings Credit Agreement. Borrowings under the Holdings Credit Agreement may be repaid from time to time without penalty.

The Holdings Credit Agreement contains covenants including, among others, the following:

The Holdings Credit Agreement contains customary events of default, including our failure to comply with the 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 the Holdings Credit Agreement to be immediately due and payable.

In connection with Athlon's incorporation on April 1, 2013 under the laws of the State of Delaware, it issued 1,000 shares of its common stock to Athlon Holdings GP LLC for an aggregate purchase price of $10.00. On April 26, 2013, in connection with Athlon's reorganization transactions, certain holders of limited partner interests in Holdings exchanged their Class A interests and Class B interests for an aggregate of 960,907 shares of Athlon's common stock. In connection with the effectiveness of Athlon's IPO, these shares were subject to an adjustment based on Athlon's IPO price of $20.00 per share and an actual 65.266-for-1 stock split resulting in 66,339,615 shares of Athlon's common stock to be outstanding prior to the closing of the IPO.

As discussed in "Note 1. Formation of the Company and Description of Business", on August 7, 2013, Athlon completed its IPO of 15,789,474 shares of its 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. Athlon used the net proceeds from the IPO to purchase New Holdings Units from Holdings. Holdings used the proceeds it received as a result of Athlon's purchase of New Holdings Units (i) to reduce outstanding borrowings under the Holdings Credit Agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes, including potential acquisitions. Upon consummation of the IPO, Athlon's ownership percentage of Holdings increased, resulting in a decrease in the noncontrolling interest from approximately 3.2% to approximately 2.2%.

During the third quarter of 2013, Athlon recorded a reclassification of approximately $12.5 million from "Retained earnings" to "Additional paid-in capital" on the accompanying Consolidated Statement of Changes in Equity related to derivative activity that occurred prior to Athlon's corporate reorganization on April 26, 2013. This resulted in a decrease in "Net income attributable to noncontrolling interest" on the accompanying Consolidated Statements of Operations of approximately $0.4 million during the third quarter of 2013.

Prior to the consummation of Athlon's IPO, Athlon had 960,907 shares of outstanding common stock. In conjunction with the closing of the IPO, certain Class A limited partners and Class B limited partners of Holdings that exchanged their interests for shares of Athlon's common stock were subject to an adjustment based on Athlon's IPO price of $20.00 per share and an actual 65.266-for-1 stock split. Following this adjustment and stock split, the number of outstanding shares of Athlon's common stock increased from 960,907 shares to 66,339,615 shares. The one-to-one conversion of the Holdings interests in April 2013 to 960,907 shares of Athlon common stock that occurred in connection with the IPO is akin to a stock split and has been treated as such in Athlon's earnings per share ("EPS") calculations. Accordingly, Athlon assumes that 66,339,615 shares of common stock were outstanding during periods prior to Athlon's IPO for purposes of calculating EPS.

The following table reflects the allocation of net income (loss) to common stockholders and EPS computations for the periods indicated:

	Three months ended September 30,						Nine months ended September 30,

	2013			2012			2013			2012
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	2,482		$	(2,096	)	$	37,058		$	42,508
Participation rights of unvested RSUs in undistributed earnings		(6	)		—			(6	)		—

Basic undistributed net income (loss) attributable to stockholders	$	2,476		$	(2,096	)	$	37,052		$	42,508

Denominator:
Basic weighted average shares outstanding		76,637			66,340			69,810			66,340

Basic EPS attributable to stockholders	$	0.03		$	(0.03	)	$	0.53		$	0.64

Diluted EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	2,482		$	(2,096	)	$	37,058		$	42,508
Participation rights of unvested RSUs in undistributed earnings		(6	)		—			(6	)		—
Effect of conversion of New Holdings Units to shares of Athlon's common stock		(215	)		—			616			—

Diluted undistributed net income (loss) attributable to stockholders	$	2,261		$	(2,096	)	$	37,668		$	42,508

Denominator:
Basic weighted average shares outstanding		76,637			66,340			69,810			66,340
Effect of conversion of New Holdings Units to shares of Athlon's common stock(a)		1,856			—			1,856			1,856

Diluted weighted average shares outstanding		78,493			66,340			71,666			68,196

Diluted EPS attributable to stockholders	$	0.03		$	(0.03	)	$	0.53		$	0.62

In August 2013, Athlon adopted the Athlon Energy Inc. 2013 Incentive Award Plan (the "Plan"). The principal purpose of the Plan will be to attract, retain and engage selected employees, consultants, and directors through the granting of equity and equity-based compensation awards. Employees, consultants, and directors of Athlon and its subsidiaries are eligible to receive awards under the Plan. The Compensation Committee will administer the Plan unless our Board of Directors assumes direct authority for administration. The Plan provides for the grant of stock options (including non-qualified stock options and incentive stock options), restricted stock, dividend equivalents, stock payments, restricted stock units ("RSUs"), performance awards, stock appreciation rights, and other equity-based and cash-based awards, or any combination thereof.

Initially, the aggregate number of our shares of common stock available for issuance pursuant to awards granted under the Plan will be the sum of 8,400,000 shares, subject to adjustment as described below plus an annual increase on the first day of each calendar year beginning January 1, 2014 and ending on and including the last January 1 prior to the expiration date of the Plan, equal to the least of (i) 12,000,000 shares, (ii) 4% of the shares outstanding (on an as-converted basis) on the final day of the immediately preceding calendar year, and (iii) such smaller number of shares as determined by the Board of Directors. This number will also be adjusted due to the following shares becoming eligible to be used again for grants under the Plan:

The Plan does not provide for individual limits on awards that may be granted to any individual participant under the Plan. Rather, the amount of awards to be granted to individual participants are determined by the Board of Directors or the Compensation Committee from time to time, as part of their compensation decision-making processes, provided, however, that the Plan does not permit awards having a grant date fair value in excess of $700,000 to be granted to Athlon's non-employee directors in any year.

As of September 30, 2013, there were 7,776,087 shares available for issuance under the Plan. During the nine months ended September 30, 2013, Athlon recorded non-cash stock-based compensation expense related to the Plan of $492,000, which was allocated to lease operating expense and general and administrative expense in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees' compensation. During the nine months ended September 30, 2013, Athlon capitalized $37,000 of non-cash stock-based compensation expense related to the Plan as a component of "Proved properties, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

RSUs vest over three years, subject to performance criteria for certain members of management. The following table summarizes the changes in Athlon's unvested RSUs for the nine months ended September 30, 2013:

As of September 30, 2013, there were 396,413 unvested RSUs, all of which were granted during September 2013, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of September 30, 2013, there were 227,500 unvested RSUs, all of which were granted during September 2013, in which the vesting is dependent not only on the passage of time and continued employment, but also on the achievement of certain performance criteria.

None of Athlon's unvested RSUs are subject to variable accounting. As of September 30, 2013, Athlon had approximately $17.9 million of total unrecognized compensation cost related to unvested RSUs, which is expected to be recognized over a weighted-average period of approximately 2.8 years.

Holdings' limited partnership agreement provided for the issuance of Class B limited partner interests. As discussed in "Note 1. Formation of the Company and Description of Business", in connection with Holdings' corporate reorganization, the holders of the Class B limited partner interests in Holdings exchanged their interests for common stock of Athlon subject to the same conditions and vesting terms. Upon the consummation of Athlon's IPO on August 1, 2013, the remaining unvested common stock awards, which were formerly Class B interests in Holdings, vested and Athlon recognized non-cash equity-based compensation expense of approximately $1.5 million.

During the nine months ended September 30, 2013 and 2012, Athlon recorded approximately $1.3 million and $186,000, respectively, of non-cash equity-based compensation expense related to Class B interests, which was allocated to lease operating expense and general and administrative expenses in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees' compensation. During the nine months ended September 30, 2013 and 2012, Athlon capitalized approximately $421,000 and $68,000, respectively, of non-cash stock-based compensation expense related to Class B interests as a component of "Proved properties, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

From time to time, Athlon is a party to ongoing legal proceedings in the ordinary course of business, including workers' compensation claims and employment related disputes. Management does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on Athlon's business, financial position, results of operations, or liquidity.

Additionally, Athlon has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, commodity derivative contracts, operating leases, and development commitments.

Holdings was a party to a Transaction Fee Agreement, dated August 23, 2010, which required Holdings to pay a fee to Apollo equal to 2% of the total equity contributed to Holdings, as defined in the agreement, in exchange for consulting and advisory services provided by Apollo. In October 2012, Apollo assigned its rights and obligations under the Transaction Fee Agreement to an affiliate, Apollo Global Securities, LLC. Upon the consummation of Athlon's IPO, Holdings terminated the Transaction Fee Agreement. Since Holdings' inception through the termination of the Transaction Fee Agreement, it incurred transaction fees under the Transaction Fee Agreement of approximately $7.5 million in total.

Holdings was a party to a Services Agreement, dated August 23, 2010, which required Holdings to compensate Apollo for consulting and advisory services equal to the higher of (i) 1% of earnings before interest, income taxes, DD&A, and exploration expense per quarter and (ii) $62,500 per quarter (the "Advisory Fee"); provided, however, that such Advisory Fee for any calendar year shall not exceed $500,000. The Services Agreement also provided for reimbursement to Apollo for any reasonable out-of-pocket expenses incurred while performing services under the Services Agreement. During the nine months ended September 30, 2013 and 2012, Holdings incurred approximately $500,000 and $493,000, respectively, of Advisory Fees. All fees incurred under the Services Agreement are included in "General and administrative expenses" in the accompanying Consolidated Statements of Operations.

Upon the consummation of Athlon's IPO, Holdings terminated the Services Agreement and, in connection with the termination, Holdings paid $2.4 million (plus $132,000 of unreimbursed fees) 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). Under the Services Agreement, Holdings also agreed to indemnify Apollo and its affiliates and their respective limited partners, general partners, directors, members, officers, managers, employees, agents, advisors, their directors, officers, and representatives for potential losses relating to the services contemplated under the Services Agreement.

Participation of Apollo Global Securities, LLC in Senior Notes Offering and IPO

Apollo Global Securities, LLC is an affiliate of the Apollo Funds and received a portion of the gross spread as an initial purchaser of the Notes of $0.5 million. Apollo Global Securities, LLC was

also an underwriter in Athlon's IPO and received a portion of the discounts and commissions paid to the underwriters in the IPO of approximately $0.9 million.

Holdings used a portion of the net proceeds from the Notes to make a distribution to its Class A limited partners, including the Apollo Funds and its management team and employees. The Apollo Funds received approximately $73 million of the distribution and the remaining Class A limited partners received approximately $2 million, in the aggregate.

Upon the consummation of its IPO, Athlon entered into an exchange agreement with certain members of its management team and employees who hold New Holdings Units after the closing of the IPO. Under the exchange agreement, each such holder (and certain permitted transferees thereof) may, under certain circumstances after the date of the closing of the IPO (subject to the terms of the exchange agreement), exchange their New Holdings Units for shares of Athlon's common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications. As a holder exchanges its New Holdings Units, Athlon's interest in Holdings will be correspondingly increased.

Upon the consummation of its IPO, Athlon entered into a tax receivable agreement with certain members of its management team and employees who hold New Holdings Units after the closing of the IPO that provides for the payment from time to time by Athlon to such unitholders of Holdings of 85% of the amount of the benefits, if any, that Athlon is deemed to realize as a result of increases in tax basis and certain other tax benefits related to exchanges of New Holdings Units pursuant to the exchange agreement, including tax benefits attributable to payments under the tax receivable agreement. These payment obligations are obligations of Athlon and not of Holdings. For purposes of the tax receivable agreement, the benefit deemed realized by Athlon will be computed by comparing its actual income tax liability (calculated with certain assumptions) to the amount of such taxes that Athlon would have been required to pay had there been no increase to the tax basis of the assets of Holdings as a result of the exchanges and had Athlon not entered into the tax receivable agreement.

The step-up in basis will depend on the fair value of the New Holdings Units at conversion. There is no intent of the holders of New Holdings Units to exchange their units for shares of Athlon's common stock in the foreseeable future. In addition, Athlon does not expect to be in a tax paying position before 2019. Therefore, Athlon cannot presently estimate what the benefit or payments under the tax receivable agreement will be on a factually supportable basis, and accordingly not recognized as a liability.

In November 2013, Holdings amended the Holdings Credit Agreement to, among other things, increase the borrowing base to $525 million. As of November 14, 2013, there were no of outstanding borrowings under the Holdings Credit Agreement.

We have audited the accompanying consolidated balance sheets of Athlon Energy Inc. (the "Company") (formerly, "Athlon Holdings LP") as of December 31, 2012 and 2011, and the related consolidated statements of operations, changes in equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Athlon Energy Inc. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

Fort Worth, Texas
March 8, 2013,
except for Note 1 and Note 11, as to which the date is
January 24, 2014

	December 31,

	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	8,871		$	32,030
Accounts receivable		24,501			17,181
Derivatives		2,246			—
Inventory		1,022			751
Other		2,486			1,574

Total current assets		39,126			51,536

Properties and equipment, at cost—full cost method:
Proved properties, including wells and related equipment		788,571			399,205
Unproved properties		89,860			125,036
Accumulated depletion, depreciation, and amortization		(73,824	)		(19,589	)

		804,607			504,652

Derivatives		2,854			2,503
Debt issuance costs		4,418			2,264
Other		1,293			868

Total assets	$	852,298		$	561,823

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	3,170		$	3,214
Affiliate		935			4,581
Accrued liabilities:
Lease operating		3,858			2,568
Production, severance, and ad valorem taxes		1,307			2,592
Development capital		39,483			30,863
Derivatives		592			5,908
Revenue payable		9,330			5,710
Other		2,700			2,036

Total current liabilities		61,375			57,472
Derivatives		519			2,554
Asset retirement obligations		5,049			3,704
Long-term debt		362,000			170,000
Other		2,478			641

Total liabilities		431,421			234,371

Commitments and contingencies
Equity		420,877			327,452

Total liabilities and equity	$	852,298		$	561,823

The accompanying notes are an integral part of these consolidated financial statements.

	Year ended December 31,

	2012			2011
Revenues:
Oil	$	128,081		$	51,193
Natural gas		8,415			3,521
Natural gas liquids		20,615			10,967

Total revenues		157,111			65,681

Expenses:
Production:
Lease operating		25,503			13,328
Production, severance, and ad valorem taxes		10,438			4,727
Depletion, depreciation, and amortization		54,456			19,747
General and administrative		9,678			7,724
Acquisition costs		876			9,519
Derivative fair value loss (gain)		(9,293	)		7,959
Other operating		562			404

Total expenses		92,220			63,408

Operating income		64,891			2,273
Interest expense		9,949			2,932

Income (loss) before income taxes		54,942			(659	)
Income tax provision		1,928			470

Net income (loss)	$	53,014		$	(1,129	)

Net income (loss) per common share:
Basic	$	0.80		$	(0.02	)
Diluted	$	0.78		$	(0.02	)
Weighted average common shares outstanding:
Basic		66,340			66,340
Diluted		68,196			66,340

The accompanying notes are an integral part of these consolidated financial statements.

	Year ended December 31,

	2012			2011
Cash flows from operating activities:
Net income (loss)	$	53,014		$	(1,129	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		54,456			19,747
Deferred taxes		1,928			470
Non-cash derivative loss (gain)		(9,947	)		7,509
Equity-based compensation		152			106
Other		1,758			963
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(7,320	)		(16,963	)
Other current assets		(337	)		(1,691	)
Other assets		—			(16	)
Accounts payable		(2,140	)		537
Revenue payable		3,620			5,710
Derivatives		—			(1,950	)
Other current liabilities		118			5,579

Net cash provided by operating activities		95,302			18,872

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(80,602	)		(414,759	)
Development of oil and natural gas properties		(266,235	)		(57,457	)
Monetization of put options		—			7,625
Other		(422	)		(884	)

Net cash used in investing activities		(347,259	)		(465,475	)

Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		519,672			198,651
Payments on long-term debt		(331,000	)		(31,000	)
Capital contributions from partners		40,166			303,976
Other		(40	)		—

Net cash provided by financing activities		228,798			471,627

Increase (decrease) in cash and cash equivalents		(23,159	)		25,024
Cash and cash equivalents, beginning of period		32,030			7,006

Cash and cash equivalents, end of period	$	8,871		$	32,030

The accompanying notes are an integral part of these consolidated financial statements.

In the corporate 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 Holdings for common stock of Athlon. The remaining holders of Class A limited partner interests in Holdings did not exchange their interests in the reorganization transactions. In addition, the holders of the Class B limited partner interests in Holdings exchanged their interests for common stock of Athlon subject to the same conditions and vesting terms.

Holdings was formed on July 22, 2011, and is the holding company for Athlon Energy LP (together with its operating subsidiary, Athlon Energy Operating LLC, "Athlon SG"), a Delaware limited partnership, which was formed on August 5, 2010, and Athlon FE Energy LP (together with its operating subsidiary, Athlon FE Operating LLC, "Athlon FE"), a Delaware limited partnership, which was formed on July 22, 2011. Athlon Holdings LLC serves as the general partner to Holdings with no obligations to make capital contributions and no rights to distributions. Holdings owns all of Athlon SG's and Athlon FE's general partner and limited partner units.

On August 23, 2010, Athlon SG entered into a limited partnership agreement with its management group and Apollo. Apollo has a controlling influence over Holdings. On July 22, 2011, the partnership agreement was amended and restated resulting in the formation of Holdings and Athlon FE. Upon formation, Holdings became the holding company of Athlon SG and Athlon FE. The amended and restated partnership agreement required all of Athlon SG's equity contributions to be contributed to Holdings. The holders of all Class A and Class B limited partner units in Athlon SG contributed these units to Holdings in exchange for equivalent units of Holdings. As the amendment of the partnership agreement constituted a reorganization of entities under common control, the operations of Athlon SG are presented as if Holdings existed and owned Athlon SG prior to July 22, 2011 and the assets and liabilities of Athlon SG are reflected at their carrying amounts. Please read "Note 7. Equity" and "Note 8. Employee Benefit Plans" for additional discussion.

Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities in the consolidated financial statements. Although management believes these estimates are reasonable, actual results could differ materially from those estimates.

Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization ("DD&A") expense; operating costs accrued; volumes and prices for revenues accrued; valuation of derivative instruments; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on results in future periods.

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits.

The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

Accounts receivable, which are primarily from the sale of oil, natural gas, and natural gas liquids ("NGLs"), is accrued based on estimates of the sales and prices Athlon believes it will receive. Athlon routinely reviews outstanding balances, assesses the financial strength of its customers, and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2012 and 2011, Athlon had no allowance for doubtful accounts.

Inventory includes materials and supplies that Athlon intends to deploy to various development activities and oil in tanks at the lease, both of which are stated at the lower of cost (determined on an average basis) or market. Oil in tanks at the lease is carried at an amount equal to its costs to produce. Inventory consisted of the following as of the dates indicated:

Athlon applies the provisions of the "Extractive Activities—Oil and Gas" topic of the Financial Accounting Standards Board's (the "FASB") Accounting Standards Codification (the "ASC"). Athlon uses the full cost method of accounting for its 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.

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 depletion, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, 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 partners' 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. Athlon uses 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. Athlon has not designated any of its commodity derivative contracts as cash flow hedges and has therefore not included its 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.

Natural gas volumes are converted to barrels of oil equivalent ("BOE") at the rate of six thousand cubic feet ("Mcf") of natural gas to one barrel ("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.

Independent petroleum engineers estimate Athlon's proved reserves annually on December 31. This results in a new DD&A rate which Athlon uses for the preceding fourth quarter after adjusting for fourth quarter production. Athlon internally estimates 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.

Athlon capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During 2012, Athlon capitalized approximately $0.2 million of interest expense. During 2011, Athlon did not capitalize any interest expense.

Amounts shown in the accompanying Consolidated Balance Sheets as "Proved properties, including wells and related equipment" consisted of the following as of the date indicated:

Athlon applies the provisions of the "Asset Retirement and Environmental Obligations" topic of the ASC. Athlon has obligations as a result of lease agreements and enacted laws to remove its 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, Athlon records a separate liability for the estimated fair value of its asset retirement obligations, with an offsetting increase to the related oil and natural gas asset representing asset retirement costs in the accompanying Consolidated Balance Sheets. The cost of the related oil and natural gas asset, including the asset retirement cost, is included in Athlon's 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 Athlon's 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.

abandonment liability, Athlon makes 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. Please read "Note 5. Asset Retirement Obligations" for additional information.

Athlon operates in only one industry: the oil and natural gas exploration and production industry in the United States. All revenues are derived from customers located in the United States.

The following purchasers accounted for 10% or greater of the sales of production for the periods indicated and the corresponding outstanding accounts receivable balance as of the dates indicated:

Prior to its corporate reorganization, Athlon was treated as a partnership for federal and state income tax purposes with each partner being separately taxed on their share of Athlon's taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying Consolidated Financial Statements. However, Athlon's operations located in Texas are subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 0.7% of income that is apportioned to Texas. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective Texas margin tax bases.

Net income (loss) for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual partners have different investment bases depending upon the timing and price of acquisition of their partnership units, and each partner's tax accounting, which is partially dependent upon the partner's tax position, differs from the accounting followed in the accompanying Consolidated Financial Statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as Athlon does not have access to information about each partner's tax attributes in Holdings.

Athlon performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in its consolidated financial statements. As of December 31,

2012 and 2011, all of Athlon's tax positions met the "more-likely-than-not" threshold. As a result, no additional tax expense, interest, or penalties have been accrued.

Revenues from the sale of oil, natural gas and NGLs are recognized when the production is sold, net of any royalty interest. Because final settlement of Athlon's hydrocarbon sales can take up to two months, the expected sales volumes and prices for those properties are estimated and accrued using information available at the time the revenue is recorded. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than Athlon's proportionate share of natural gas production. If Athlon's overproduced imbalance position (i.e., Athlon has cumulatively been over-allocated production) is greater than its share of remaining reserves, a liability would be recorded for the excess at period-end prices unless a different price is specified in the contract, in which case that price is used. At December 31, 2012 and 2011, Athlon did not have any natural gas imbalances. Revenue is not recognized for oil production in tanks, but the production is recorded as a current asset based on the cost to produce and included in "Inventory" in the accompanying Consolidated Balance Sheets. Transportation expenses are included in operating expenses and are not material.

Athlon applies the provisions of the "Derivatives and Hedging" topic of the ASC, which requires each derivative instrument to be recorded in the accompanying Consolidated Balance Sheets 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. Athlon elected not to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in "Derivative fair value loss (gain)" in the accompanying Consolidated Statements of Operations.

Athlon enters into commodity derivative contracts for the purpose of economically hedging the price of its anticipated oil production even though Athlon does not designate the derivatives as hedges for accounting purposes. Athlon classifies 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 Athlon's oil and natural gas operations, they are classified as cash flows from operating activities in the accompanying Consolidated Statements of Cash Flows. During 2011 and 2012, Athlon entered into commodity derivative contracts all of which were for the purpose of economically hedging its anticipated oil production.

Cash flows relating to commodity derivative contracts that were entered into prior to Athlon commencing oil and natural gas operations in January 2011 are classified as investing activities in the accompanying Consolidated Statements of Cash Flows.

In May 2011, the FASB issued Accounting Standards Update ("ASU") 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs". ASU 2011-04 amended ASC 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting Standards. Certain of the amendments clarified the application of existing fair value measurement requirements, while other amendments changed a particular principle in ASC 820. In addition, ASU 2011-04 required additional fair value disclosures. The amendments were effective for annual periods beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on Athlon's financial position, results of operations, or liquidity.

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 create new disclosure requirements regarding the nature of an entity's rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements, and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs will not impact Athlon's financial position, results of operations, or liquidity.

No other new accounting pronouncements issued or effective during 2012, or in 2013 through the date of this report, had or are expected to have a material impact on Athlon's consolidated financial statements.

In December 2012, Athlon FE acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas from Cobra Oil & Gas Corporation and certain of its subsidiaries and affiliates for approximately $48.3 million in cash, which was financed through a $40 million capital contribution from Apollo and borrowings under Athlon's credit agreement. The operations of these properties have been included with those of Athlon FE from the date of acquisition.

On October 3, 2011, Athlon FE acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas from Element Petroleum, LP ("Element") for approximately $253.2 million in cash, which was financed through borrowings under Athlon FE's then-existing credit agreement and capital contributions from partners. The operations of these properties have been included with those of Athlon FE from the date of acquisition. Athlon FE incurred approximately $6.4 million of transaction costs related to this acquisition, which are included in "General and administrative expenses" in the accompanying Consolidated Statements of Operations. Of this amount, approximately $4.3 million was paid to Apollo. Please read "Note 10. Related Party Transactions" for additional discussion.

The allocation of the purchase price to the fair value of the assets acquired and liabilities assumed from Element was as follows (in thousands):

The following unaudited pro forma condensed financial data was derived from the historical financial statements of Athlon and from the accounting records of Element to give effect to the acquisition as if it had occurred on January 1, 2011. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Element acquisition taken place on January 1, 2011 and is not intended to be a projection of future results.

On January 6, 2011, Athlon SG acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas from SandRidge Exploration and Production, LLC ("SandRidge") for approximately $156.0 million in cash, which was financed through borrowings under Athlon SG's then-existing credit agreement and capital contributions from partners. The operations of these properties have been included with those of Athlon SG from the date of acquisition. Athlon SG incurred $2.6 million of transaction costs related to this acquisition, which are included in "General and administrative expenses" in the accompanying Consolidated Statements of Operations. Of this amount, approximately $2.3 million was paid to Apollo. Please read "Note 10. Related Party Transactions" for additional discussion.

The allocation of the purchase price to the fair value of the assets acquired and liabilities assumed from SandRidge was as follows (in thousands):

Athlon leases certain office space that has non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2012:

Athlon's operating lease rental expense was approximately $507 thousand and $272 thousand during 2012 and 2011, respectively.

Athlon is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on Athlon's business, financial position, results of operations, or liquidity.

Athlon is a party to a second lien term loan agreement dated September 5, 2012 (the "Second Lien"), which matures on November 21, 2017. The Second Lien provides for term loans to be made to Athlon in the aggregate amount of up to $125 million. At December 31, 2012, there were $125 million outstanding loans under the Second Lien. Athlon used the net proceeds from the Second Lien to reduce outstanding borrowings under its credit agreements.

Obligations under the Second Lien are secured by a second-priority security interest in substantially all of Athlon's proved reserves and in the equity interests of its operating subsidiaries. In addition, obligations under the Second Lien are fully and unconditionally guaranteed by Athlon's operating subsidiaries.

Loans under the Second Lien are subject to varying rates of interest based on whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the Second Lien bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Second Lien bear interest at the base rate plus the applicable margin indicated in the following table:

The "Eurodollar rate" for any interest period (either one, two, three, or six months, as selected by Athlon) is equal to the British Bankers Association London Interbank Offered Rate ("LIBOR") divided by 1.00 minus the rate prescribed by the Board of Governors of the Federal Reserve System for determining the maximum reserve requirements in respect of Eurocurrency liabilities for a member of

the Federal Reserve System in New York City. The "Base Rate" is calculated as the highest of: (1) the annual rate of interest announced by Wells Fargo Bank, N.A. as its "prime rate"; (2) the federal funds effective rate plus 0.5%; or (3) LIBOR plus 1.0%.

Borrowings under the Second Lien may be repaid from time to time without penalty, except during 2015 in which case there is a 1.0% pre-payment fee.

As of December 31, 2012, Athlon was in compliance with all covenants of the Second Lien.

The Second Lien contains customary events of default, 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 Wells Fargo Energy Capital, Inc. to declare all amounts outstanding under the Second Lien to be immediately due and payable.

Athlon SG was a party to a credit agreement dated January 6, 2011 (as amended, the "SG Credit Agreement"), which was scheduled to mature on January 6, 2016. In May 2012, all outstanding borrowings under the SG Credit Agreement were repaid with borrowings under Athlon's credit agreement discussed below and the SG Credit Agreement was terminated.

Athlon FE was a party to a credit agreement dated October 3, 2011 (as amended, the "FE Credit Agreement"), which was scheduled to mature on October 3, 2016. In May 2012, all outstanding borrowings under the FE Credit Agreement were repaid with borrowings under Athlon's credit agreement discussed below and the FE Credit Agreement was terminated.

Athlon is a party to a credit agreement dated May 21, 2012 (as amended, the "Athlon Credit Agreement"), which matures on May 21, 2017. Upon entering into the Athlon Credit Agreement, all outstanding borrowings under each of the SG Credit Agreement and the FE Credit Agreement were repaid and the agreements were terminated. On September 5, 2012, Athlon amended the Athlon Credit Agreement to, among other things: (1) exclude amounts due to Apollo under the Transaction Fee Agreement from consolidated current liabilities in the calculation of consolidated current ratio; (2) provide for a reduction in the borrowing base of 20% of any amount incurred under the Second Lien in excess of $100 million; (3) waive the current ratio requirement for the quarter ended June 30, 2012; and (4) reaffirm the borrowing base at $245 million.

The Athlon Credit Agreement provides for revolving credit loans to be made to Athlon from time to time and letters of credit to be issued from time to time for the account of Athlon or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the Athlon Credit Agreement is $700 million. Availability under the Athlon Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. On December 31, 2012, the borrowing base was $275 million and there were $237 million of outstanding borrowings, $38 million of borrowing capacity, and no outstanding letters of credit under the Athlon Credit Agreement.

Athlon incurs a quarterly commitment fee at a rate of 0.5% per year on the unused portion of the Athlon Credit Agreement.

Obligations under the Athlon Credit Agreement are secured by a first-priority security interest in substantially all of Athlon's proved reserves and in the equity interests of its operating subsidiaries. In addition, obligations under the Athlon Credit Agreement are guaranteed by Athlon's operating subsidiaries.

Loans under the Athlon 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 the Athlon Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under

the Athlon Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

The "Eurodollar rate" for any interest period (either one, two, three, or six months, as selected by Athlon) 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 the Athlon Credit Agreement. Borrowings under the Athlon Credit Agreement may be repaid from time to time without penalty.

The Athlon Credit Agreement contains covenants including, among others, the following:

As of December 31, 2012, Athlon was in compliance with all covenants of the Athlon Credit Agreement.

The Athlon Credit Agreement contains customary events of default, 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 the Athlon Credit Agreement to be immediately due and payable.

The following table shows Athlon's long-term debt maturities as of December 31, 2012:

During 2012 and 2011, the weighted-average interest rate for total indebtedness was 4.3% and 3.8%, respectively.

On August 23, 2010, Athlon SG entered into a limited partnership agreement with its management group and Apollo. On July 22, 2011, the partnership agreement was amended and restated resulting in the formation of Holdings. The amended and restated partnership agreement required all of Athlon SG's equity contributions to be contributed to Holdings. The holders of all Class A and Class B limited partner units in Athlon SG contributed these units to Holdings in exchange for equivalent units of Holdings. Apollo and Holdings' management group are Class A limited partners. The following table shows the partnership interest in Holdings as of December 31, 2012:

As of December 31, 2012, Athlon had remaining capital commitments of approximately $38.1 million from Apollo and none from management.

Athlon made contributions to its 401(k) plan, which is a voluntary and contributory plan for eligible employees based on a percentage of employee contributions, of approximately $454 thousand

and $219 thousand during 2012 and 2011, respectively. Athlon's 401(k) plan does not allow employees to invest in securities of Athlon.

Holdings' limited partnership agreement provides for the issuance of Class B limited partner interests. The Class B interests entitle the holder to participate in the net profits of Holdings, but are subject to various performance criteria. Class A interest holders are entitled to a return of their initial investment plus interest compounded at 8% annually (the "Class A Preference Amount"). Upon the occurrence of a liquidity event and after the Class A Preference Amount has been satisfied, 80% and 20% of the remaining net profits will be distributed to holders of Class A interests and Class B interests, respectively. The Class B interests vest over four or five years or upon certain performance thresholds being met by Holdings. Class B interests can also vest on the occurrence of certain events such as a change in control or in some cases upon termination of employment with Holdings. The total number of Class B interests that may be issued pursuant to the partnership agreement is 100,000. As of December 31, 2012, there were 6,200 Class B interests available for issuance under the partnership agreement. Class B interests that are forfeited will again become available for issuance under the partnership agreement.

Management evaluated the terms of the Class B interests granted during 2010, in particular the potential impact of the performance criteria on the potential value of the Class B interests, and concluded that any compensation expense related to those grants would have been nominal. Management had independent valuations of its Class B interests granted during 2012 and 2011 and recorded approximately $152 thousand and $106 thousand, respectively, of non-cash equity-based compensation expense, which was allocated to LOE and general and administrative expenses in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees' cash compensation. During 2012, Athlon also capitalized approximately $93 thousand of non-cash stock-based compensation expense as a component of "Proved properties, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

The fair value of Class B interests granted was estimated on the grant date using an option pricing model based on the following assumptions for the periods indicated:

The expected volatility was calculated based on the average historical volatility of each company in Athlon's peer group based on historical stock price data. The expected term of the Class B interests was based on expectations about future behavior. The risk-free interest rate was based on the U.S. Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the Class B interests.

The following table summarizes the changes in Holdings' Class B interests for the periods indicated:

The following table provides information regarding the expected vesting of Holdings' outstanding Class B interests at December 31, 2012:

As of December 31, 2012, Athlon had approximately $1.0 million of total unrecognized compensation cost related to unvested Class B interests, which is expected to be recognized over a weighted-average period of approximately 3.7 years. During 2012 and 2011, there were 20,375 and 19,046, respectively, Class B interests that vested, the total fair value of which was approximately $231 thousand and $59 thousand, respectively.

The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book values of the Athlon Credit Agreement and the Second Lien approximate fair value as the interest rates are variable. Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

Commodity prices are often subject to significant volatility due to many factors that are beyond Athlon's 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. Athlon's objective is to manage its exposure to oil price risk with swaps, puts, and collars. Swaps provide a fixed price for a notional amount of sales volumes. Puts provide a fixed floor price on

a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. This participation is limited by a ceiling price specified in the contract.

The following table summarizes open commodity derivative contracts as of December 31, 2012:

In January 2011, Athlon terminated certain oil puts that were in place at December 31, 2010 and received net proceeds of approximately $7.6 million, which is reflected as "Monetization of put options" in the "Investing activities" section of the accompanying Consolidated Statements of Cash Flows. In July and August 2011, Athlon entered into additional oil puts that included deferred premiums. These deferred premiums increased Athlon's interest expense by approximately $0.2 million during 2011. In October 2011, Athlon terminated the oil puts and entered into oil swaps that required the initial payment of premiums of approximately $2.0 million.

Counterparty Risk. At December 31, 2012, Athlon had committed 10% or greater (in terms of fair market value) of its oil derivative contracts in asset positions from the following counterparties:

Athlon does not require collateral from its counterparties for entering into financial instruments, so in order to mitigate the credit risk associated with financial instruments, Athlon enters into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and Athlon. Instead of treating each financial transaction between the counterparty and Athlon separately, the master netting agreement enables the counterparty and Athlon to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit Athlon 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 Athlon's credit exposure to a given counterparty in the event of close-out. Athlon's accounting policy is to not offset fair value amounts between different counterparties for derivative instruments in the accompanying Consolidated Balance Sheets.

The following table summarizes the fair value of Athlon's derivative instruments as of the dates indicated (in thousands):

The following table summarizes the effect of derivative instruments not designated as hedges on the accompanying Consolidated Statements of Operations for the periods indicated (in thousands):

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are defined as follows:

As required by GAAP, Athlon utilizes 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. Athlon's 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 and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of Athlon's assets and liabilities that are accounted for at fair value on a recurring basis:

Athlon adjusts the valuations from the valuation model for nonperformance risk. For commodity derivative contracts which are in an asset position, Athlon uses the counterparty's credit default swap rating. For commodity derivative contracts which are in a liability position, Athlon uses the average credit default swap rating of its peer companies as Athlon does not have its own credit default swap rating. All fair values have been adjusted for nonperformance risk resulting in an increase in the net commodity derivative asset of approximately $0.1 million as of December 31, 2012 and a decrease of the net commodity derivative liability of approximately $0.5 million as of December 31, 2011.

The following table sets forth Athlon's assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated:

				Fair Value Measurements at Reporting Date Using

Description	Asset (liability), net			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(in thousands)
As of December 31, 2012
Oil derivative contracts—swaps	$	4,069		$	—	$	4,069		$	—
Oil derivative contracts—collars and puts		(80	)		—		(80	)		—

Total	$	3,989		$	—	$	3,989		$	—

As of December 31, 2011
Oil derivative contracts—swaps	$	(5,392	)	$	—	$	(5,392	)	$	—
Oil derivative contracts—collars and puts		(567	)		—		—			(567	)

Total	$	(5,959	)	$	—	$	(5,392	)	$	(567	)

Athlon's oil collars were classified as Level 3 in the fair value hierarchy as of December 31, 2011. Beginning in 2012, these contracts were classified as Level 2 in the fair value hierarchy as a result of

Athlon's ability to obtain appropriate volatilities. The following table summarizes the changes in the fair value of Athlon's Level 3 assets and liabilities that were previously classified as Level 3 for the periods indicated:

Since Athlon does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in "Derivative fair value loss (gain)" in the accompanying Consolidated Statements of Operations.

Athlon is a party to a Transaction Fee Agreement, dated August 23, 2010, which requires Athlon to pay a fee to Apollo equal to 2% of the total equity contributed to Athlon, as defined in the agreement, in exchange for consulting and advisory services provided by Apollo. In October 2012, Apollo assigned its rights and obligations under the Transaction Fee Agreement to Apollo Global Securities, LLC. In December 2012, Athlon incurred a transaction fee payable to Apollo Global Securities, LLC of $0.8 million related to a $40 million capital contribution received from Apollo. Upon the closing of the SandRidge acquisition in January 2011, Athlon SG incurred a transaction fee payable to Apollo of approximately $2.3 million. Upon the closing of the Element acquisition in October 2011, Athlon FE incurred a transaction fee payable to Apollo of approximately $4.3 million. All transaction fees incurred under the Transaction Fee Agreement are included in "Acquisition costs" in the accompanying Consolidated Statements of Operations during the period incurred.

Athlon is also a party to a Services Agreement, dated August 23, 2010, which requires Athlon to further compensate Apollo for consulting and advisory services equal to a minimum of $62,500 per quarter or 1% of net income before interest, income taxes, and DD&A, not to exceed $500,000 in any calendar year. The Services Agreement also provides for reimbursement to Apollo for any reasonable out-of-pocket expenses incurred while performing under the Services Agreement. During 2012 and

2011, Athlon incurred approximately $493 thousand and $411 thousand, respectively, of fees under the Services Agreement, which is included in "General and administrative expenses" in the accompanying Consolidated Statements of Operations.

Prior to the consummation of Athlon's IPO, Athlon had 960,907 shares of outstanding common stock. In conjunction with the closing of the IPO, certain Class A limited partners and Class B limited partners of Holdings that exchanged their interests for shares of Athlon's common stock were subject to an adjustment based on Athlon's IPO price of $20.00 per share and an actual 65.266-for-1 stock split. Following this adjustment and stock split, the number of outstanding shares of Athlon's common stock increased from 960,907 shares to 66,339,615 shares. The one-to-one conversion of the Holdings' interests in April 2013 to 960,907 shares of Athlon common stock that occurred in connection with the IPO is akin to a stock split and has been treated as such in Athlon's earnings per share ("EPS") calculations. Accordingly, Athlon assumes that 66,339,615 shares of common stock were outstanding during periods prior to Athlon's IPO for purposes of calculating EPS.

The following table reflects the allocation of net income (loss) to common stockholders and EPS computations for the periods indicated:

	Year ended December 31,

	2012		2011
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Basic undistributed net income (loss) attributable to stockholders	$	53,014	$	(1,129	)

Denominator:
Basic weighted average shares outstanding		66,340		66,340

Basic EPS attributable to stockholders	$	0.80	$	(0.02	)

Diluted EPS
Numerator:
Diluted undistributed net income (loss) attributable to stockholders	$	53,014	$	(1,129	)

Denominator:
Basic weighted average shares outstanding		66,340		66,340
Effect of conversion of New Holdings Units to shares of Athlon's common stock(a)		1,856		—

Diluted weighted average shares outstanding		68,196		66,340

Diluted EPS attributable to stockholders	$	0.78	$	(0.02	)

In January 2013, Athlon increased the borrowing base under the Athlon Credit Agreement to $295 million.

During February 2013, Athlon entered into additional oil swaps. The following table summarizes open commodity derivative contracts as of March 8, 2013:

In February 2013, Athlon also entered into basis differential swaps for 5,000 Bbls/D at $1.20/Bbl for March through December 2013.

These financial statements considered subsequent events through March 8, 2013, the date the consolidated financial statements were available to be issued.

Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities

The capitalized cost of oil and natural gas properties was as follows as of the dates indicated:

The following table summarizes costs incurred related to oil and natural gas properties for the periods indicated:

All of Athlon's results of operations relate to oil and natural gas producing activities. Athlon only has one cost center, which is the Permian Basin in West Texas. Athlon's average depletion rate per BOE of production was $21.03 and $20.32 for 2012 and 2011, respectively.

The estimates of Athlon's proved reserves, which are located entirely within the United States, were prepared in accordance with rules and regulations established by the FASB. Proved oil and natural gas reserve quantities are based on internal estimates reviewed by independent petroleum engineers.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. Estimates of future net cash flows from Athlon's properties, and the representative value thereof, were made using 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. Prices used in estimating Athlon's future net cash flows were as follows as of the dates indicated:

Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. Future cash inflows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and the estimated effect of future income taxes due to the Texas margin tax. Future federal income taxes have not been deducted from future net revenues in the calculation of Athlon's standardized measure as each partner is separately taxed on his share of Athlon's taxable income.

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 engineering, 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. Reserve estimates are integral to management's analysis of impairment of oil and natural gas properties and the calculation of DD&A on these properties.

Athlon's estimated net quantities of proved reserves were as follows as of the dates indicated:

	December 31,

	2012		2011
Proved developed reserves:
Oil (MBbls)		14,470		7,942
Natural gas (MMcf)		31,965		14,063
Natural gas liquids (MBbls)		5,900		3,211
Combined (MBOE)		25,698		13,496
Proved undeveloped reserves:
Oil (MBbls)		34,953		18,030
Natural gas (MMcf)		71,718		37,497
Natural gas liquids (MBbls)		13,375		8,338
Combined (MBOE)		60,281		32,618
Proved reserves:
Oil (MBbls)		49,423		25,972
Natural gas (MMcf)		103,683		51,560
Natural gas liquids (MBbls)		19,275		11,549
Combined (MBOE)		85,979		46,114

The changes in Athlon's proved reserves were as follows for the periods indicated:



Balance at December 31, 2010	—		—		—		—
Purchases of minerals-in-place	21,308		39,179		8,935		36,773
Extensions and discoveries	4,200		10,064		2,285		8,162
Revisions of previous estimates	1,020		3,334		568		2,143
Production	(556	)	(1,017	)	(239	)	(964	)

Balance, December 31, 2011	25,972		51,560		11,549		46,114
Purchases of minerals-in-place	5,203		5,874		1,162		7,344
Extensions and discoveries	23,471		56,736		10,525		43,452
Revisions of previous estimates(1)	(3,766	)	(7,324	)	(3,366	)	(8,352	)
Production	(1,457	)	(3,163	)	(595	)	(2,579	)

Balance, December 31, 2012	49,423		103,683		19,275		85,979

The following is a standardized measure of the discounted net future cash flows and changes applicable to proved reserves. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management's opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of

production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of Athlon's proved oil and natural gas properties.

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

Athlon's standardized measure of discounted estimated future net cash flows was as follows as of the dates indicated:

The changes in Athlon's standardized measure of discounted estimated future net cash flows were as follows for the periods indicated:

	Year ended December 31,

	2012			2011
	(in thousands)
Net change in prices and production costs	$	(109,214	)	$	73,093
Purchases of minerals-in-place		81,304			394,248
Extensions, discoveries, and improved recovery		376,493			101,396
Revisions of previous quantity estimates		(189,505	)		27,499
Production, net of production costs		(121,170	)		(47,626	)
Previously estimated development costs incurred during the period		119,361			43,994
Accretion of discount		59,144			20,072
Change in estimated future development costs		60,210			(22,239	)
Net change in income taxes		(5,378	)		(2,809	)
Change in timing and other		(1,488	)		(6,471	)

Net change in standardized measure		269,757			581,157
Standardized measure, beginning of year		581,157			—

Standardized measure, end of year	$	850,914		$	581,157

We have audited the accompanying carve out balance sheet of Element Petroleum, LP's ("Element") Permian Basin Operations as defined in Note 1 as of September 30, 2011, and the related carve out statements of operations, owner's net equity, and cash flows for the nine months then ended. These financial statements are the responsibility of Athlon Holdings LP's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of Element's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Element's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the carve out financial position of Element's Permian Basin Operations included in the Purchase and Sale Agreement with Athlon FE Operating LLC at September 30, 2011 and the carve out results of its operations and its cash flows for the nine months then ended in conformity with U.S. generally accepted accounting principles.

	September 30, 2011

ASSETS
Current assets:
Accounts receivable	$	2,253
Inventory		271

Total current assets		2,524

Properties and equipment, at cost—successful efforts method:
Proved properties, including wells and related equipment		121,568
Unproved properties		13,515
Accumulated depletion, depreciation, and amortization		(30,732	)

		104,351

Other property and equipment		939
Accumulated depreciation		(173	)

		766

Other		73

Total assets	$	107,714

LIABILITIES AND OWNER'S NET EQUITY
Current liabilities:
Accounts payable	$	6,501
Accrued liabilities:
Lease operating		170
Production, severance, and ad valorem taxes		401
Development capital		2,516
Revenues payable		1,802
Other		305

Total current liabilities		11,695
Asset retirement obligations		1,754

Total liabilities		13,449

Commitments and contingencies (see Note 3)
Owner's net equity		94,265

Total liabilities and owner's net equity	$	107,714

The accompanying notes are an integral part of these carve out financial statements.

	Nine Months Ended September 30, 2011

Revenues:
Oil	$	17,406
Natural gas		6,109
Management fees		422

Total revenues		23,937

Expenses:
Production:
Lease operating		1,962
Production, severance, and ad valorem taxes		1,590
Depletion, depreciation, and amortization		5,594
General and administrative		1,897
Accretion		62

Total expenses		11,105

Operating income		12,832
Interest, net		1

Net income	$	12,833

The accompanying notes are an integral part of these carve out financial statements.

	Nine Months Ended September 30, 2011

Cash flows from operating activities:
Net income	$	12,833
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		5,594
Accretion		62
Changes in operating assets and liabilities:
Accounts receivable		(1,563	)
Inventory		89
Accounts payable		(1,118	)
Other current liabilities		3,470

Net cash provided by operating activities		19,367

Cash flows from investing activities:
Acquisition of oil and natural gas properties		(2,085	)
Development of oil and natural gas properties		(53,640	)
Other		(33	)

Net cash used in investing activities		(55,758	)

Cash flows from financing activities:
Net contributions from owner		36,391

Net cash provided by financing activities		36,391

Increase (decrease) in cash and cash equivalents		—
Cash and cash equivalents, beginning of period		—

Cash and cash equivalents, end of period	$	—

Non-cash investing activities:
Establishment of asset retirement obligations	$	639

The accompanying notes are an integral part of these carve out financial statements.

Athlon FE Energy LP together with its subsidiary, ("Athlon FE"), a Delaware limited partnership, was formed on July 22, 2011 (the "date of inception"), and is the holding company for Athlon FE Operating LLC (the "Company"), which was also formed on July 22, 2011. Athlon FE seeks to execute a low-risk "acquire and exploit" strategy by establishing a footprint in proven oil and natural gas basins with initial acquisitions of mature producing properties that have long-lived, predictable reserves in the onshore continental United States. On October 3, 2011, the Company acquired certain oil and natural gas properties from Element Petroleum, LP ("Element") in the Permian Basin of West Texas (the "Permian Basin Operations") for approximately $253.2 million.

The accompanying carve out financial statements and related notes thereto represent the financial position, results of operations, changes in owner's net equity, and cash flows of the Permian Basin Operations. The carve out financial statements have been prepared in accordance with Regulation S-X, Article 3, "General instructions as to financial statements" and Staff Accounting Bulletin ("SAB") Topic 1-B, "Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity". Certain expenses incurred by Element are only indirectly attributable to its ownership of the Permian Basin Operations as Element owns interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to the Permian Basin Operations so that the accompanying carve out financial statements reflect substantially all the costs of doing business borne by Element on behalf of the Permian Basin Operations. These allocations may not be indicative of the cost of future operations or the amount of future allocations. The allocations and related estimates and assumptions are described more fully in "Note 2. Summary of Significant Accounting Policies" and "Note 5. Related Party Transactions".

The accompanying carve out financial statements were derived from the accounting records of Element.

The accompanying carve out financial statements have been prepared in accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting, legal services, and other expenses. Element has allocated general and administrative expenses to the Permian Basin Operations using an average of its proportionate share of Element's consolidated oil and natural gas revenues, capital expenditures, and well count. Management believes the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by Element on behalf of the Permian Basin Operations. These allocations may not be indicative of the cost of future operations or the amount of future allocations.

Preparing carve out financial statements in conformity with accounting principles generally accepted in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities in the carve out financial statements. Also, certain amounts in the accompanying carve out financial statements have been allocated in a way that management believes is

reasonable and consistent in order to depict the historical financial position, results of operations, and cash flows of the Permian Basin Operations on a stand-alone basis. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Estimates made in preparing these carve out financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization ("DD&A") expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on results in future periods.

Element provided cash as needed to support the Permian Basin Operations and collected cash from sales of production. Consequently, the accompanying Carve Out Balance Sheet do not include any cash balances. Net cash paid from Element to the Permian Basin Operations is reflected as net contributions from owner on the accompanying Carve Out Statement of Owner's Net Equity and Carve Out Statement of Cash Flows.

Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest. Element routinely reviews outstanding accounts receivable balances, assesses the financial strength of its customers, and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At September 30, 2011, the Permian Basin Operations had no allowance for doubtful accounts.

Oil and Natural Gas Properties. The Permian Basin Operations use the successful efforts method of accounting for its oil and natural gas properties under the provisions of the "Financial Accounting and Reporting by Oil and Gas Producing Companies" topic of the Financial Accounting Standards Board's (the "FASB") Accounting Standards Codification (the "ASC"). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the accompanying Carve Out Statement of Operations and shown as an adjustment to net income in the "Operating activities" section of the accompanying Carve Out Statement of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, the associated cost continues to be capitalized as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that

these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed and shown as an adjustment to net income in the "Operating activities" section of the accompanying Carve Out Statement of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is unsuccessful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as "Development of oil and natural gas properties" in the "Investing activities" section of the accompanying Carve Out Statement of Cash Flows.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent ("BOE") at the rate of six thousand cubic feet ("Mcf") of natural gas to one barrel ("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.

DD&A of capitalized costs for producing oil and natural gas properties is provided for using the unit-of-production method based on estimates of proved oil and natural gas reserves on a field-by-field basis. Costs of significant nonproducing properties, wells in progress of being drilled, and development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

Reserve engineers estimate the reserves of the Permian Basin Operations annually on December 31.

In accordance with the provisions of the "Accounting for the Impairment or Disposal of Long-Lived Assets" topic of the ASC, management assesses the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent the asset's carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves, forecasted production information, and management's outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. Management uses prices consistent with the prices it believes a market participant would use in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.

Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties' costs which management believes will not be transferred to proved properties over the remaining life of the lease.

Amounts shown in the accompanying Carve Out Balance Sheet as "Proved properties, including wells and related equipment" consisted of the following as of the date indicated:

Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years. Gains or losses from the disposal of other property and equipment are recognized in the period realized.

Management applies the provisions of the "Accounting for Asset Retirement Obligation" topic of the ASC. The Permian Basin Operations have significant obligations under its lease agreements and federal regulation to remove its equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations are primarily associated with plugging and abandoning wells and land remediation. Estimating the future restoration and removal cost is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. At the time the well is drilled, the Permian Basin Operations record a separate liability for the estimated fair value of its asset retirement obligations, with an offsetting increase to the related oil and natural gas properties representing asset retirement costs in the accompanying Carve Out Balance Sheet. The cost of the related oil and natural gas asset, including the asset retirement cost, is included in the Permian Basin Operations' capitalized property costs. 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 Element's credit-adjusted, risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Inherent to the present-value calculation are numerous estimates, assumptions, and judgments, including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted, risk-free rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions affect the present value of the abandonment liability, management makes corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. Increases in the discounted asset retirement obligations resulting from the passage of time are reflected as additional accretion expense in the accompanying Carve Out Statement of Operations. Please read "Note 4. Asset Retirement Obligations" for additional information.

The change in net assets that is not attributable to current period earnings is reflected as net contributions from owner for that period. As the Permian Basin Operations were not a separate legal entity during the period covered by these carve out financial statements, none of Element's debt is directly attributable to its ownership of the Permian Basin Operations, and no formal intercompany financing arrangement exists related to the Permian Basin Operations. Additionally, as debt cannot be specifically ascribed to the Permian Basin Operations, the accompanying Carve Out Statement of Operations do not include any allocation of interest expense incurred by Element related to the Permian Basin Operations.

The Permian Basin Operations operate in only one industry: the oil and natural gas exploration and production industry in the United States. All revenues are derived from customers located in the United States.

The following purchasers accounted for 10% or greater of the sales of production for the period indicated and the corresponding outstanding accounts receivable balance as of the date indicated:

Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties. Royalties are incurred based upon the actual price received from the sales. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those

properties are estimated and recorded as "Accounts receivable" in the accompanying Carve Out Balance Sheet. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than the Permian Basin Operations' proportionate share of natural gas production. If the Permian Basin Operations' overproduced imbalance position (i.e., the Permian Basin Operations have cumulatively been over-allocated production) is greater than its share of remaining reserves, a liability would be recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. At September 30, 2011, the Permian Basin Operations had no oil inventories in pipelines or tanks and it had no natural gas imbalances. Revenue is not recognized for oil production in tanks.

During the period presented, the Permian Basin Operations were wholly owned by Element. Accordingly, earnings per share is not presented.

Financial instruments in the accompanying Carve Out Balance Sheet include accounts receivable and accounts payable. The book values of accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments.

In May 2011, the FASB issued Accounting Standards Update ("ASU") 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs". ASU 2011-04 amended ASC 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting Standards. Certain of the amendments clarify the application of existing fair value measurement requirements, while other amendments change a particular principle in ASC 820. In addition, ASU 2011-04 requires additional fair value disclosures. The amendments will be applied prospectively and are effective for annual periods beginning after December 15, 2011. Management does not believe the adoption of this guidance will have a material impact on the Permian Basin Operations' financial position, results of operations, or liquidity.

In December 2011, the FASB issued ASU 2011-11, "Disclosures about offsetting Assets and Liabilities" requiring additional disclosure about offsetting and related arrangements. ASU 2011-11 is effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of ASU 2011-11 will not impact the Permian Basin Operations' position, results of operations, or liquidity.

No other new accounting pronouncements issued or effective during 2011 had or are expected to have a material impact on the Permian Basin Operations' carve out financial statements.

The Permian Basin Operations are subject to various possible contingencies. Such contingencies include environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates and

environmental matters are subject to regulation by various federal and state agencies. Additionally, the Permian Basin Operations have contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties as discussed in "Note 4. Asset Retirement Obligations".

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Permian Basin Operations' asset retirement obligations for the period indicated:

The employees supporting the operations of the Permian Basin Operations are employees of Element's management company. Accordingly, Element recognizes all employee-related expenses and liabilities in its consolidated financial statements. In addition to employee payroll-related expenses, Element incurred general and administrative expenses related to leasing office space and other corporate overhead expenses during the period covered by these carve out financial statements. For purposes of deriving the accompanying carve out financial statements, Element allocated general and administrative expenses to the Permian Basin Operations using an average of its proportionate share of Element's consolidated oil and natural gas revenues, capital expenditures, and well count. For the nine months ended September 30, 2011, the portion of Element's consolidated general and administrative expenses allocated to the Permian Basin Operations was 60.4%, or approximately $1.9 million.

These carve out financial statements considered subsequent events through May 16, 2012, the date the financial statements were available to be issued. No subsequent events requiring recognition or disclosure have occurred.

Citigroup
Goldman, Sachs & Co.
BofA Merrill Lynch
Barclays
RBC Capital Markets
Tudor, Pickering, Holt & Co.
UBS Investment Bank
Wells Fargo Securities
Apollo Global Securities
Scotiabank / Howard Weil
Simmons & Company
International
Stephens Inc.
CIBC
Mitsubishi UFJ Securities
Academy Securities, Inc.
KLR Group, LLC

	Per Share		Total

Public Offering Price	$	32.00	$	448,000,000
Underwriting Discounts and Commissions(1)	$	1.28	$	17,920,000
Proceeds to the selling stockholders (before expenses)	$	30.72	$	430,080,000


Citigroup		Goldman, Sachs & Co.
BofA Merrill Lynch	Barclays	RBC Capital Markets
Tudor, Pickering, Holt & Co.	UBS Investment Bank	Wells Fargo Securities

Period	High		Low

Third Quarter 2013(1)	$	33.98	$	25.25
Fourth Quarter 2013	$	34.59	$	26.91
First Quarter 2014 (through February 6, 2014)	$	34.08	$	26.97

	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	)

	Nine months ended September 30,

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


Apollo Global Securities	Scotiabank / Howard Weil	Simmons & Company International
Stephens Inc.	CIBC	Mitsubishi UFJ Securities
Academy Securities, Inc.		KLR Group, LLC


Prospectus Summary		1
The Offering		10
Summary Consolidated Financial, Reserve and Operating Data		12
Risk Factors		20
Cautionary Note Regarding Forward-Looking Statements		50
Use of Proceeds		52
Market Price of Our Common Stock		52
Dividend Policy		52
Capitalization		53
Selected Historical Consolidated Financial Data		54
Management's Discussion and Analysis of Financial Condition and Results of Operations		55
Business		85
Management		110
Certain Relationships and Related Party Transactions		129
Corporate Reorganization		135
Principal and Selling Stockholders		137
Description of Capital Stock		139
Shares Eligible for Future Sale		146
Material U.S. Federal Income Tax Consequences to Non-U.S. Holders		148
Underwriting (Conflicts of Interest)		152
Legal Matters		159
Experts		159
Where You Can Find More Information		159
Glossary		G-1
Index to Financial Statements		F-1

	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	%

	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

Ratio of Outstanding Borrowings to Borrowing Base

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	%

			Identified Drilling Locations(1)				Estimated Net Proved Reserves(2)

	Net Acreage(1)		Identified Drilling Locations(1)						Average WI/NRI	% Developed
Area	Net Acreage(1)		Gross		Net		MMBOE		Average WI/NRI	% Developed
Howard		54,902		3,322		2,516		33.5	92%/71%		26	%
Midland & Other		33,709		879		799		33.3	93%/71%		35	%
Glasscock		13,112		689		623		19.2	95%/73%		27	%

Total		101,723		4,890		3,938		86.0	93%/72%		30	%

	Acres Expiring

	Gross		Net
2014		8,871		4,004
2015		10,325		8,087
2016		39,649		24,527
2017		—		—
2018		—		—

Total		58,845		36,618


Expected volatility		34.1	%
Expected dividend yield		0.0	%
Expected term (in years)		0.53
Risk-free interest rate		0.11	%
Weighted-average grant-date fair value per unit	$	109.22


Expected volatility		47.3	%
Expected dividend yield		0.0	%
Expected term (in years)		1.9
Risk-free interest rate		0.8	%
Weighted-average grant-date fair value per share	$	36.16

Name	Base Salary Before Increase		Base Salary After Increase

Robert C. Reeves	$	410,000	$	570,000
Nelson K. Treadway		290,000		300,000
William Butler		250,000		290,000

Name		Total Number of RSUs(1)

Robert C. Reeves		142,500
Nelson K. Treadway		60,000
William Butler		43,500

	Stock Awards(1)

Name	Number of Shares of Stock That Have Not Vested		Market Value of Shares of Stock That Have Not Vested(2)		Equity Incentive Plan Awards: Number of Unearned Shares That Have Not Vested(3)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares That Have Not Vested(2)
Robert C. Reeves		142,500	$	4,310,625		N/A		N/A
Nelson K. Treadway		60,000		1,815,000		N/A		N/A
William Butler		43,500		1,315,875		N/A		N/A

Name	Fees Earned or Paid in Cash		Stock Awards(1)		Total

Ted A. Gardner	$	50,000	$	240,300	$	290,300
Mark A. Stevens		50,000		240,300		290,300

		Page

*ATHLON ENERGY INC*.
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012			F-2
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012			F-3
Consolidated Statements of Changes in Equity for the Nine Months Ended September 30, 2013			F-4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012			F-5
Notes to Consolidated Financial Statements			F-6
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm			F-25
Consolidated Balance Sheets as of December 31, 2012 and 2011			F-26
Consolidated Statements of Operations for the Years Ended December 31, 2012 and 2011			F-27
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2012 and 2011			F-28
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012 and 2011			F-29
Notes to Consolidated Financial Statements			F-30
Supplementary Information			F-54
*ELEMENT PETROLEUM, LP PERMIAN BASIN OPERATIONS*
AUDITED CARVE OUT FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm			F-59
Carve Out Balance Sheet as of September 30, 2011			F-60
Carve Out Statement of Operations for the Nine Months Ended September 30, 2011			F-61
Carve Out Statement of Changes in Owner's Net Equity for the Nine Months Ended September 30, 2011			F-62
Carve Out Statement of Cash Flows for the Nine Months Ended September 30, 2011			F-63
Notes to Carve Out Financial Statements			F-64

	Three months ended September 30, 2013		Nine months ended September 30, 2013

	(in thousands)
Net income attributable to stockholders	$	2,482	$	37,058

Transfer from noncontrolling interest:
Increase in Athlon's paid-in capital for corporate reorganization		—		290,950
Increase in Athlon's paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering		295,473		295,473

Net transfer from noncontrolling interest		295,473		586,423

Change from net income attributable to stockholders and transfers from (to) noncontrolling interest	$	297,955	$	623,481

	September 30, 2013		December 31, 2012

	(in thousands)
Proved leasehold costs	$	411,657	$	376,271
Wells and related equipment—Completed		634,980		379,036
Wells and related equipment—In process		38,244		33,264

Total proved properties	$	1,084,881	$	788,571

		Amount of Loss (Gain) Recognized in Income

		Three months ended September 30,				Nine months ended September 30,
	Location of Loss (Gain) Recognized in Income	Three months ended September 30,				Nine months ended September 30,
Derivatives Not Designated as Hedges	Location of Loss (Gain) Recognized in Income	2013		2012		2013		2012
Commodity derivative contracts	Derivative fair value loss (gain)	$	27,037	$	14,268	$	21,331	$	(9,590	)


Balance at January 1	$	5,049
Liabilities assumed in acquisitions		335
Liabilities incurred from new wells		735
Liabilities settled		(108	)
Accretion of discount		485
Revisions of previous estimates		3

Balance at September 30		6,499
Less: current portion		60

Asset retirement obligations—long-term	$	6,439

		Weighted- Average Grant Date Fair Value

Outstanding at January 1	—	$	—
Granted	623,913		32.21
Vested	—		—
Forfeited	—		—

Outstanding at September 30	623,913		32.21

	Total Equity

Balance at December 31, 2010	$	24,499
Capital contributions from partners		303,976
Equity-based compensation		106
Net loss		(1,129	)

Balance at December 31, 2011		327,452
Capital contributions from partners		40,166
Equity-based compensation		245
Net income		53,014

Balance at December 31, 2012	$	420,877

	Percentage of Total Revenues for the Year Ended December 31,						Outstanding Accounts Receivable Balance as of December 31,

Purchaser	2012			2011			2012		2011
							(in thousands)
Occidental Petroleum Corporation		29	%		58	%	$	4,456	$	5,863
DCP Midstream		12	%		13	%		2,604		2,716
Pecos Gathering & Marketing		43	%		13	%		9,348		3,756


Proved properties, including wells and related equipment	$	130,527
Unproved properties		123,107
Other assets		806

Total assets acquired		254,440

Current liabilities		831
Asset retirement obligations		393

Total liabilities assumed		1,224

Fair value of net assets acquired	$	253,216

	Year ended December 31, 2011

	(in thousands)
Pro forma total revenues	$	89,618

Pro forma net income	$	9,777


Proved properties, including wells and related equipment	$	158,157
Oil inventory		637

Total assets acquired		158,794
Asset retirement obligations		2,778

Fair value of net assets acquired	$	156,016

	Payments Due by Period

	Total		2013		2014		2015		2016		2017		Thereafter
	(in thousands)
Corporate office lease	$	1,412	$	381	$	375	$	375	$	281	$	—	$	—
Midland office lease		375		90		92		96		97		—		—

Total	$	1,787	$	471	$	467	$	471	$	378	$	—	$	—

Period

September 5, 2012 through December 31, 2013	6.50	%	5.50	%
January 1, 2014 through December 31, 2014	6.75	%	5.75	%
January 1, 2015 through December 31, 2015	7.00	%	6.00	%
January 1, 2016 and thereafter	7.25	%	6.25	%

The Months Immediately Following Any Date of Determination

1st through the 24th month	90	%	65	%
25th through the 36th month	85	%	50	%
37th and each succeeding month	85	%	0	%

Ratio of Outstanding Borrowings to Borrowing Base

Less than .50 to 1	2.00	%	1.00	%
Greater than or equal to .50 to 1 but less than .75 to 1	2.25	%	1.25	%
Greater than or equal to .75 to 1 but less than .90 to 1	2.50	%	1.50	%
Greater than or equal to .90 to 1	2.75	%	1.75	%



Athlon Holdings LLC	General Partner	0.0	%
Apollo Athlon Holdings LLC	Class A Partner	97.2	%
Management group	Class A Partner	2.8	%

	Year Ended December 31,

	2012					2011
	Number of Class B Interests			Weighted- Average Grant Date Fair Value		Number of Class B Interests			Weighted- Average Grant Date Fair Value
Outstanding at beginning of period		68,662		$	15.93		82,153		$	—
Granted		2,195			128.94		9,050			134.84
Vested		(20,375	)		11.32		(19,046	)		3.11
Forfeited		(270	)		140.72		(3,495	)		19.13

Outstanding at end of year		50,212			22.07		68,662			15.93