10-K

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

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to

Commission File Number: 001-36026

ATHLON ENERGY INC.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	46-2549833 (I.R.S. Employer Identification No.)
420 Throckmorton Street, Suite 1200, Fort Worth, Texas (Address of principal executive offices)	76102 (Zip Code)

Registrant's telephone number, including area code: (817) 984-8200

         Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $0.01 Par Value	New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

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

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

         Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity of the registrant began trading on the New York Stock Exchange (August 2, 2013) $410,526,324

         As of March 7, 2014, we had 82,129,089 outstanding shares of our common stock, $0.01 par value.

DOCUMENTS INCORPORATED BY REFERENCE

         Parts of the definitive proxy statement for the registrant's 2014 annual meeting of stockholders are incorporated by reference into Part III of this report on Form 10-K.

ATHLON ENERGY INC.

INDEX

		Page
PART I
Items 1. and 2.	Business and Properties		1
Item 1A.	Risk Factors		23
Item 1B.	Unresolved Staff Comments		48
Item 3.	Legal Proceedings		48
Item 4.	Mine Safety Disclosures		48
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		49
Item 6.	Selected Financial Data		51
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		82
Item 8.	Financial Statements and Supplementary Data		84
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		122
Item 9A.	Controls and Procedures		122
Item 9B.	Other Information		122
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		124
Item 11.	Executive Compensation		124
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		124
Item 13.	Certain Relationships and Related Transactions, and Director Independence		124
Item 14.	Principal Accounting Fees and Services		124
PART IV
Item 15.	Exhibits, Financial Statement Schedules		125

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GLOSSARY

        The following are abbreviations and definitions of certain terms used in this annual report on Form 10-K (the "Report"):

•

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.

•

Bbl/D.  One Bbl per day.

•

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

•

BOE/D.  One barrel of oil equivalent per day.

•

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.

•

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.

•

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.

•

FASB.  Financial Accounting Standards Board.

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•

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).

•

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.

•

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

•

GAAP.  Accounting principles generally accepted in the United States.

•

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

•

Holdings.  Athlon Holdings LP, our accounting predecessor.

•

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.

•

LIBOR.  London Interbank Offered Rate.

•

MBbl.  One thousand barrels of crude oil, condensate, or NGLs.

•

MBOE.  One thousand barrels of oil equivalent.

•

Mcf.  One thousand cubic feet of natural gas.

•

MMBOE.  One million barrels of oil equivalent.

•

MMBtu.  One million British thermal units.

•

MMcf.  One million cubic feet of natural gas.

•

MMcf/D.  One million cubic feet of natural gas per day.

•

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.

•

NYMEX.  The New York Mercantile Exchange.

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•

NYSE.  The New York Stock Exchange.

•

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.

•

Production margin.  Total wellhead revenues less total production costs.

•

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:



i.

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or



ii.

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

•

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.

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•

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.

•

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.

•

SEC.  The United States Securities and Exchange Commission.

•

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.

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•

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.

•

Workover.  Operations on a producing well to restore or increase production.

•

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.

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ATHLON ENERGY INC.

        In this Report, 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. This Report contains forward-looking statements, which give our current expectations or forecasts of future events. Please read "Item 1A. Risk Factors" for a description of various factors that could materially affect our ability to achieve the anticipated results described in the forward-looking statements. Certain terms commonly used in the oil and natural gas industry and in this Report are defined under the caption "Glossary". In addition, all production and reserve volumes disclosed in this Report represent amounts net to us, unless otherwise noted.

PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

General

        We are a Delaware corporation formed on April 1, 2013. 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 focused on the low-risk vertical development of stacked pay zones, including the Clearfork, Spraberry, Wolfcamp, Cline, Strawn, Atoka, and Mississippian formations, which we refer to collectively as the Wolfberry play, and horizontal development of the Wolfcamp. 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 over 20 years of industry experience and over 10 years of history working together, our founding management has a proven track record of working as a team to acquire, develop, and exploit oil and natural gas reserves in the Permian Basin as well as other resource plays in North America.

        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. Our common stock began trading on the NYSE on August 2, 2013 under the symbol "ATHL". The net proceeds from our IPO were approximately $295.7 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.

        Our acreage position was 127,840 gross (104,059 net) acres at December 31, 2013. During 2013, we drilled 171 gross operated vertical Wolfberry wells and commenced drilling four gross operated horizontal Wolfcamp wells with a 100% success rate. This activity has allowed us to identify and de-risk our multi-year inventory of 4,848 gross (3,908 net) vertical drilling locations, while also identifying 1,065 gross (964 net) horizontal drilling locations in specific areas based on geophysical and technical data, as of December 31, 2013. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify additional horizontal drilling locations.

        As of December 31, 2013, we have identified 2,232 gross (1,784 net) vertical drilling locations on 40-acre spacing and an additional 2,616 gross (2,124 net) vertical drilling locations on 20-acre spacing.

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ATHLON ENERGY INC.

Only 659 gross (632 net) of these potential vertical drilling locations were booked as PUDs in our proved reserve report as of December 31, 2013. These locations were 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.

        As of December 31, 2013, we have also identified 1,065 gross (964 net) horizontal drilling locations targeting Wolfcamp A, Wolfcamp B, Wolfcamp C, and Cline intervals, which comprise 327 gross (295 net), 362 gross (330 net), 136 gross (127 net), and 240 gross (212 net) locations, respectively.

        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. In 2013, our development capital was approximately $398.7 million and we drilled 171 gross operated vertical Wolfberry wells and commenced drilling four gross operated horizontal Wolfcamp wells with a 100% success rate and grew our production to 14,689 BOE/D in the fourth quarter of 2013.

        In 2014, we expect our drilling capital expenditures to be $595 million, plus an additional $20 million for infrastructure, leasing, and capitalized workovers, and we expect to drill 205 gross vertical Wolfberry wells and 21 gross horizontal Wolfcamp wells. We currently operate eight vertical drilling rigs and one horizontal drilling rig. We expect to add a second horizontal drilling rig in the second quarter of 2014.

        Our estimate of proved reserves is prepared by Cawley, Gillespie & Associates, Inc. ("CG&A"), our independent petroleum engineers. As of December 31, 2013, we had 127.3 MMBOE of proved reserves, which were comprised of 71.2 MMBbls of oil, 30.7 MMBbls of NGLs, and 152.2 Bcf of natural gas. As of December 31, 2013, 37% of our proved reserves were proved developed and our PUDs were composed of 659 gross (632 net) potential vertical drilling locations. As of December 31, 2013, the PV-10 of our proved reserves was approximately $1.6 billion, 61% of which was attributed to proved developed reserves. PV-10 is a non-GAAP financial measure. Standardized Measure is the closest GAAP measure and our Standardized Measure was approximately $1.1 billion at December 31, 2013. Standardized Measure differs from PV-10 by approximately $535.8 million because Standardized Measure includes the effects of future income taxes.

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 2013, we invested $398.7 million of development capital, drilled 171 gross (165 net) vertical Wolfberry wells, commenced drilling four gross (four net) horizontal Wolfcamp wells, and grew production by 5,979 BOE/D, or 69%, from 8,710 BOE/D in the fourth quarter of 2012 to 14,689 BOE/D in the fourth quarter of 2013. We also increased proved reserves by 41.3 MMBOE, or 48%, from 86.0 MMBOE at December 31, 2012 to 127.3 MMBOE at December 31, 2013.

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ATHLON ENERGY INC.

•

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, including us, 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 would offer competitive rates of return. We expect to add a second horizontal rig in the second quarter of 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, multiple smaller acquisitions, and leasehold 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.

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Our Competitive Strengths

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

•

High caliber management team with substantial technical and operational expertise.  Our founding management team has an average of over 20 years of industry experience and over 10 years of history working together with a proven track record of value creation at publicly traded oil and natural gas companies, including Encore Acquisition Company, XTO Energy Inc., Apache Corporation, and Anadarko Petroleum Corporation. As of 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 56% and 24% of our proved reserves were oil and NGLs, respectively, as of December 31, 2013.

•

De-risked Midland Basin acreage position with multi-year vertical drilling inventory.  During 2013, we drilled 171 gross operated vertical Wolfberry wells and commenced drilling four gross operated horizontal Wolfcamp wells with a 100% 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 December 31, 2013, we have identified 2,232 gross (1,784 net) vertical drilling locations on 40-acre spacing and an additional 2,616 gross (2,124 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. 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 and Cline 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 our initial horizontal activity, vertical well control information from our operations, and the operations of offset operators, we have identified horizontal drilling locations in the Wolfcamp A, Wolfcamp B, Wolfcamp C, and Cline formations of 327 gross (295 net), 362 gross (330 net), 136 gross (127 net), and 240 gross (212 net), respectively. 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 Clearfork, Spraberry, Strawn, Atoka, and Mississippian formations. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify

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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 would offer competitive rates of return. We expect to add a second horizontal rig in the second quarter of 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, 2013, we operated properties comprising over 99% of our proved reserves.

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"), our management team and certain employees owned all of the Class A limited partner interests in Athlon Holdings LP and 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 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 that we refer to as the "New Holdings Units". 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.

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        The diagram below sets forth our simplified organizational structure as of March 7, 2014. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us.

Our Properties

        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, total production from the Permian Basin during December 2013 was approximately 2.2 MMBOE/D, of which 62% was oil. As of December 31, 2013, there were 473 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.

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        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 Clearfork, 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 2013, industry drilling activity in the Midland Basin continued to show a trend toward horizontal development. 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, Occidental Petroleum Corporation, and Laredo Petroleum Holdings, Inc.

        Drilling Activity.    During 2013, we drilled 171 gross (165 net) operated vertical wells and commenced drilling four gross (four net) operated horizontal wells and our development capital was approximately $398.7 million. As of December 31, 2013, we had 127,840 gross (104,059 net) acres and an inventory of 2,232 gross (1,784 net) identified vertical drilling locations based on 40-acre spacing and an additional 2,616 gross (2,124 net) identified vertical drilling locations based on 20-acre spacing. As of December 31, 2013, we have also identified 1,065 gross (964 net) horizontal drilling locations consisting of 327 gross (295 net) Wolfcamp A locations, 362 gross (330 net) Wolfcamp B locations, 136 gross (127 net) Wolfcamp C locations, and 240 gross (212 net) Cline locations. We are currently operating eight vertical drilling rigs and one horizontal drilling rig.

        In 2014, we expect to drill 205 gross vertical Wolfberry wells and 21 gross horizontal Wolfcamp wells. In this Report, 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.

        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 10 saltwater disposal systems with over 45,700 barrels of water per day capacity and access to over 144 fresh water supply wells throughout our acreage. In addition, we have established pipeline infrastructures to reduce our need for trucking services.

Oil and Natural Gas Data

Proved Reserves

        Evaluation and Review of Proved Reserves.    Our historical proved reserve estimates were prepared by CG&A. 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. A copy of the independent petroleum engineering firm's proved reserve report as of December 31, 2013 is attached hereto as an exhibit.

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        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 meets 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 20 years of reservoir and operations experience.

        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:

•

review and verification of historical production data, which data is based on actual production as reported by us;

•

preparation of reserve estimates by Ms. Palko or under her direct supervision;

•

review by Ms. Palko of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

•

direct reporting responsibilities by Ms. Palko to our Chief Executive Officer; and

•

verification of property ownership by our land department.

        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, 2013 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: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) 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

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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 the dates indicated, based on the proved reserve reports prepared by CG&A 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. A copy of the proved reserve report as of December 31, 2013 is included as an exhibit to this Report. 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 in connection with this Report.

	December 31,
	2013		2012		2011
Proved developed reserves:
Oil (MBbls)		26,436		14,470		7,942
Natural gas (MMcf)		55,358		31,965		14,063
Natural gas liquids (MBbls)		11,077		5,900		3,211
Combined (MBOE)		46,740		25,698		13,496
Proved undeveloped reserves:
Oil (MBbls)		44,738		34,953		18,030
Natural gas (MMcf)		96,848		71,718		37,497
Natural gas liquids (MBbls)		19,645		13,375		8,338
Combined (MBOE)		80,524		60,281		32,618
Proved reserves:
Oil (MBbls)		71,174		49,423		25,972
Natural gas (MMcf)		152,206		103,683		51,560
Natural gas liquids (MBbls)		30,722		19,275		11,549
Combined (MBOE)		127,264		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

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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 "Item 1A. Risk Factors".

        Additional information regarding our proved reserves can be found in the supplementary information to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" and the proved reserve report as of December 31, 2013 which is included as an exhibit to this Report.

Proved Undeveloped Reserves (PUDs)

        As of December 31, 2013, our proved undeveloped reserves were composed of 44,738 MBbls of oil, 96,848 MMcf of natural gas, and 19,645 MBbls of NGLs, for a total of 80,524 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

        The following table summarizes our changes in PUDs during 2013 (in MBOE):

Balance, December 31, 2012	60,281
Purchases of minerals-in-place	361
Extensions and discoveries	27,124
Revisions of previous estimates(a)	735
Transfers to proved developed	(7,977	)
Balance, December 31, 2013	80,524

(a)

Revisions to previous estimates are comprised of 6,512 MBOE of negative revisions for PUDs that are not currently scheduled to be drilled within the next five years and 7,249 MBOE of positive net revisions due to the combination of price, cost, and technical revisions.

        Costs incurred relating to the development of PUDs reflected in our 2012 proved reserve report were $133.1 million during 2013. In addition, we incurred costs of $174.2 million to develop locations that became classified as PUDs during 2013. Estimated future development costs relating to the development of PUDs are projected to be approximately $194.9 million in 2014, $205.8 million in 2015, $240.3 million in 2016, $321.1 million in 2017, and $280.7 million in 2018. 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 2018.

        As of December 31, 2013, approximately 3% of our total proved reserves were classified as proved developed non-producing.

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Oil and Natural Gas Production Prices and Production Costs

Production and Price History

        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:

	Year Ended December 31,
	2013		2012		2011
Total production volumes:
Oil (MBbls)		2,682		1,457		556
Natural gas (MMcf)		4,927		3,163		1,017
NGLs (MBbls)		954		595		239
Combined (MBOE)		4,458		2,579		964
Average daily production volumes:
Oil (Bbls/D)		7,349		3,981		1,523
Natural gas (Mcf/D)		13,497		8,641		2,786
NGLs (Bbls/D)		2,614		1,625		654
Combined (BOE/D)		12,213		7,047		2,641
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	94.17	$	87.90	$	92.08
Oil ($/Bbl) (after impact of cash settled derivatives)		90.89		87.16		87.16
Natural gas ($/Mcf)		3.37		2.66		3.46
NGLs ($/Bbl)		31.60		34.65		45.96
Combined ($/BOE) (before impact of cash settled derivatives)		67.16		60.91		68.13
Combined ($/BOE) (after impact of cash settled derivatives)		65.18		60.50		65.29
Expenses (per BOE):
Lease operating	$	7.58	$	9.89	$	13.82
Production, severance, and ad valorem taxes		4.27		4.05		4.90
Depletion, depreciation, and amortization		19.56		21.11		20.48
General and administrative		4.79		3.75		8.01

Productive Wells

        As of December 31, 2013, we owned an average 96% working interest in 647 gross (622 net) productive oil 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.

Developed and Undeveloped Acreage

        As of December 31, 2013, we had 127,840 gross (104,059 net) acres, of which 60,234 gross (56,402 net) was developed and 67,606 gross (47,657 net) was undeveloped. Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production 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

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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 December 31, 2013:

	Acres Expiring
	Gross		Net
2014		8,651		4,086
2015		9,341		8,018
2016		36,708		23,909
2017		—		—
2018		—		—
Total		54,700		36,013

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

Drilling Results

        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.

	Year Ended December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		71		70		102		94		18		15
Dry holes		—		—		2		2		—		—
		71		70		104		96		18		15
Exploratory Wells:
Productive		102		97		29		28		5		5
Dry holes		—		—		—		—		1		1
		102		97		29		28		6		6
Total:
Productive		173		167		131		122		23		20
Dry holes		—		—		2		2		1		1
		173		167		133		124		24		21

        As of December 31, 2013, we had 19 gross (18 net) wells in the process of drilling, completing, or dewatering or shut in awaiting infrastructure that are not reflected in the above table.

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Operations

General

        As of December 31, 2013, we operated properties comprising over 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.

Marketing and Customers

        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 2013, two purchasers accounted for more than 10% of our revenues: High Sierra Crude Oil & Marketing, LLC (46%) and Occidental Petroleum Corporation (27%). 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.

Transportation

        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.

Competition

        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.

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Title to Properties

        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.

Oil and Natural Gas Leases

        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%.

Seasonal Nature of Business

        Oil and natural gas producing operations are generally not seasonal. However, demand for some of our products can fluctuate season to season, which impacts price. In particular, natural gas is generally in higher demand in the winter for heating.

Financial Information About Operating Segments

        Our only operations are in the oil and natural gas exploration and production industry in the United States.

Regulation

Environmental Matters and Regulation

        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 Environmental Protection Agency (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

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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

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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 federal Safe Drinking Water Act (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 federal Clean Air Act, as amended, (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

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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 "greenhouse gases" ("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.

        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.

Regulation of Hydraulic Fracturing

        Hydraulic fracturing is an important and 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 Underground Injection Control ("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

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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 CWA 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.

        Federal agencies are also considering additional regulation of hydraulic fracturing. On October 20, 2011, the EPA announced its intention to propose CWA 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 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.

        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. 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

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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.

        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.

Other Regulation of the Oil and Natural Gas Industry

        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,

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drilling bonds, and reports concerning operations. The state, as well as some counties and municipalities, in which we operate also regulate one or more of the following:

•

the location of wells;

•

the method of drilling and casing wells;

•

the timing of construction or drilling activities, including seasonal wildlife closures;

•

the rates of production or "allowables";

•

the surface use and restoration of properties upon which wells are drilled;

•

the plugging and abandonment of wells; and

•

notice to, and consultation with, surface owners and other third parties.

        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

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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.

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Operational Hazards and Insurance

        The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blowouts, 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.

        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.

Employees

        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.

Principal Executive Office

        Our principal executive office is located at 420 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our main telephone number is (817) 984-8400. We also lease additional office space in Midland, Texas. We believe that our facilities are adequate for our current operations.

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Available Information

        We make available electronically, free of charge through our website (www.athlonenergy.com), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and other filings with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the "Exchange Act") as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. In addition, you may read and copy any materials that we file with the SEC at its public reference room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information concerning the operation of the public reference room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy statements, and other information regarding issuers, like us, that file electronically with the SEC.

        We have adopted a code of business conduct and ethics that applies to all of our directors, officers, and employees, including our principal executive officer and principal financial officer. The code of business conduct and ethics is available on our website. In the event that we make changes in, or provide waivers from, the provisions of this code of business conduct and ethics that the SEC or the NYSE requires us to disclose, we intend to disclose these events on our website.

        Our board of directors has three standing committees: (i) audit, (ii) compensation, and (iii) nominating and corporate governance. Our board of directors committee charters, code of business conduct and ethics, and corporate governance guidelines are available on our website.

        The information on our website or any other website is not incorporated by reference into this Report.

ITEM 1A.    RISK FACTORS

You should carefully consider the following risks and all of the information contained in this Report. 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 majority 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

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us such as horizontal drilling may make it more difficult to accurately estimate these costs. Further, our drilling and producing operations may be curtailed, delayed, canceled, or otherwise negatively impacted as a result of other factors, including:

•

unusual or unexpected geological formations;

•

loss of drilling fluid circulation;

•

title problems;

•

facility or equipment malfunctions;

•

unexpected operational events;

•

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

•

reductions in oil and natural gas prices;

•

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

•

the limited availability of financing at acceptable rates;

•

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

•

adverse weather conditions.

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

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

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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.

A significant portion 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 December 31, 2013, approximately 46% of our net leasehold acreage was 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 2013, our drilling capital expenditures were $398.7 million. In 2014, we expect our drilling capital expenditures to be $595 million, plus an additional $20 million for leasing, infrastructure, and capital workovers. Notwithstanding prior contributions to us by the Apollo Funds or their affiliates, you should not assume that any of them will provide any debt or equity funding to us in the future.

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

•

our proved reserves;

•

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

•

the prices at which our production is sold;

•

the levels of our operating expenses; and

•

our ability to acquire, locate, and produce new reserves.

        We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2014 could exceed our budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint ventures, production payment financings, sales of assets, private or public offerings of debt or equity securities, or other means.

        Our 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

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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 F&D costs. Furthermore, although our revenues may increase if prevailing commodity prices increase, our F&D 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. During 2013, we drilled a 171 gross (165 net) operated vertical wells and participated in an additional nine gross (three net) non-operated wells, 19 gross (18 net) wells of which were in various stages of completion at December 31, 2013. During 2013, we also commenced drilling four gross (four net) operated horizontal wells, two gross (two net) of which were in various stages of completion at December 31, 2013. 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 December 31, 2013, we had identified 2,232 gross (1,784 net) potential vertical drilling locations on our existing acreage based on 40-acre spacing and an additional 2,616 gross (2,124 net)

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potential vertical drilling locations based on 20-acre spacing. Only 659 gross (632 net) of these potential vertical drilling locations were attributed to PUDs in our December 31, 2013 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 63% of our total proved reserves at December 31, 2013 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.

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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 "Items 1. and 2. Business and Properties—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. 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

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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. We expect to add a second horizontal drilling rig in the second quarter of 2014. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, drilling rig crews and other personnel, trucking services, tubulars, fracking and completion services, and production equipment, including equipment and personnel related to horizontal drilling activities, could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

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

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

•

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

•

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

•

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

•

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

•

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

•

the price of foreign imports;

•

political and economic conditions in oil producing countries;

•

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

•

speculative trading in crude oil and natural gas derivative contracts;

•

the level of consumer product demand;

•

weather conditions and other natural disasters;

•

risks associated with operating drilling rigs;

•

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

•

domestic and foreign governmental regulations and taxes;

•

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

•

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

•

overall domestic and global economic conditions.

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        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 $33.98 per Bbl in February 2009 to a high of $113.93 per Bbl in April 2011, 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 $6.07 per MMBtu in January 2009. During 2013, WTI prompt month contract ranged from $86.68 per Bbl to $110.53 per Bbl and the Henry Hub prompt month contract price of natural gas ranged from $3.11 per MMBtu to $4.46 per MMBtu. On December 31, 2013, the WTI prompt month contract price for crude oil was $98.42 per Bbl and the Henry Hub prompt month contract price of natural gas was $4.23 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, 2013, NGLs comprised 24% of our estimated proved reserves and accounted for 21% of our 2013 production at an average realized price of $31.60 per Bbl, a 9% drop in average price from the prior year. Our realized NGL prices decreased principally due to significant supply. The terms of our sale contracts allow purchasers of our production to elect not 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 at market-based prices. Moreover, all of our oil contracts include the Midland-Cushing differential (the difference between Midland WTI and Cushing WTI), which widened periodically during 2012 and in 2013 due to difficulty transporting oil production from the Permian Basin to the Gulf Coast refineries as a result of capacity constraints. 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, our commodity derivative contracts are based on quoted

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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 enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. Currently, we have oil swaps covering: 9,369 Bbls/D at a weighted-average price of $92.61 per Bbl for 2014 and 2,788 Bbls/D at a weighted-average price of $91.74 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 counterparty credit risk.

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

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

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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 2013, two purchasers accounted for more than 10% of our revenues: High Sierra Crude Oil & Marketing, LLC (46%) and Occidental Petroleum Corporation (27%). 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 evaluated oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. 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 $19.51, $21.03, and $20.32 for 2013, 2012, and 2011, respectively. Total depletion expense for oil and natural gas properties was $87.0 million, $54.2 million, and $19.6 million for 2013, 2012, and 2011, respectively.

        The net capitalized costs of evaluated 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 "Item 7. 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, 2013 and 2012 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

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reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future commodity prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of proved reserves, the economically recoverable quantities of reserves attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of reserves we ultimately recover being different from our estimates.

        The estimates of proved reserves as of December 31, 2013 and 2012 included in this Report 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, 2013 and 2012, respectively, in accordance with GAAP. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved acreage. The reserve estimates represent our net revenue interest in our properties.

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

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

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

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

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

•

actual prices we receive for oil and natural gas;

•

actual cost of development and production expenditures;

•

the amount and timing of actual production; and

•

changes in governmental regulations or taxation.

        The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating Standardized Measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a limited partnership, our predecessor was not subject to

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federal taxation. Accordingly, our Standardized Measure for 2012 did not provide for federal corporate income taxes because taxable income was passed through to its partners. As a corporation, we are 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 Report 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 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 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, from 2011 to 2013, Texas has experienced some of the lowest inflows of water 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.

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We may face unanticipated water and other waste disposal costs.

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

        Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

•

we cannot obtain future permits from applicable regulatory agencies;

•

water of lesser quality or requiring additional treatment is produced;

•

our wells produce excess water;

•

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

•

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

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

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

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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 borrowing capacity under our credit agreement. We may incur significant indebtedness in the future in order to make acquisitions or to develop our properties.

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

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

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

•

incur additional indebtedness;

•

create additional liens;

•

sell assets;

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merge or consolidate with another entity;

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pay dividends or make other distributions;

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•

engage in transactions with affiliates; and

•

enter into certain commodity derivative contracts.

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

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

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

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

        Our results of operations are exposed to interest rate risk associated with borrowings under our credit agreement, which bear interest at a rate elected by us that is based on the prime, LIBOR, or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the type of loan used and the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2013, 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

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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, (i) 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 (ii) 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 have a material adverse effect on 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 indemnification agreements or insurance.

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        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 "Items 1 and 2. Business and Properties—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 acquisitions or do so on commercially acceptable terms. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel, and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with these regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities, and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial, and management information systems and to attract, retain, motivate, and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our results of operations and growth. Our financial condition and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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

•

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

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

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

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

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

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

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

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•

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

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

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

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

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

        Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review from a title attorney 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 may 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 international 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.

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        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 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 (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. We may flare additional gas from time to time.

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        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 "Items 1. and 2. Business and Properties—Regulation" for a description of the laws and regulations that affect us.

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

        Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The 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

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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 CWA 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 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.

        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 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.

        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

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the federal 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

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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 Commodities Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations implementing the legislation within 360 days from the date of enactment. In its rulemaking under the legislation, the CFTC proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated numerous final rules based on its proposals, it is not possible at this time to predict when the CFTC will finalize its proposed regulations or the effect of such regulations on our business. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. This legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter,

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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

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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 2002 (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 Jumpstart Our Business Startups Act (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 our 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 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

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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.

A terrorist attack or armed conflict could harm our business.

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

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 3.    LEGAL PROCEEDINGS

        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.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

        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 following table sets forth high and low sales prices of our common stock for the periods indicated:

	High		Low
2013
Quarter ended December 31	$	34.59	$	26.91
Quarter ended September 30(a)	$	33.98	$	25.25

(a)

Represents the period from August 2, 2013, the date on which our common stock began trading on the NYSE, through September 30, 2013.

        On March 6, 2014, the closing sales price of our common stock as reported by the NYSE was $36.27 per share and we had approximately 50 stockholders of record. This number does not include owners for whom shares of common stock may be held in "street" name.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

        We did not purchase any shares of our common stock during the fourth quarter of 2013.

Dividends

        We have never declared or paid any cash dividends to holders of our common stock. We currently intend to retain all available funds, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements, and investment opportunities. In addition, our debt agreements restrict our ability to pay cash dividends to holders of our common stock.

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Stock Performance Graph

        The following graph compares our cumulative total stockholder return during the period from our IPO on August 2, 2013 to December 31, 2013 with total stockholder return during the same period for the Standard & Poor's 500 Index and the Dow Jones U.S. Oil & Gas Index. The graph assumes that (i) $100 was invested in our common stock on August 2, 2013 at its IPO price of $20 per share, (ii) $100 was invested in each index on August 2, 2013 at the closing price on such date, and (iii) all dividends, if any, were reinvested. The following graph is being furnished pursuant to SEC rules and will not be incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent we specifically incorporate it by reference.

Comparison of Total Return Since August 2, 2013 Among Athlon Energy Inc., the Standard &
Poor's 500 Index, and the Dow Jones U.S. Oil and Gas Index

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table shows selected historical financial data for the periods and as of the periods indicated. The following selected consolidated financial and operating data should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data":

	Year ended December 31,(a)
	2013			2012			2011
	(in thousands, except per share and per unit data)
Consolidated Statements of Operations Data:
Revenues:
Oil	$	252,606		$	128,081		$	51,193
Natural gas		16,620			8,415			3,521
NGLs		30,147			20,615			10,967
Total revenues		299,373			157,111			65,681
Expenses:
Production:
Lease operating		33,776			25,503			13,328
Production, severance, and ad valorem taxes		19,048			10,438			4,727
Processing, gathering, and overhead		222			84			60
Depletion, depreciation, and amortization		87,171			54,456			19,747
General and administrative		21,331			9,678			7,724
Contract termination fee(b)		2,408			—			—
Acquisition costs		421			876			9,519
Derivative fair value loss (gain)		18,115			(9,293	)		7,959
Accretion of discount on asset retirement obligations		675			478			344
Total expenses		183,167			92,220			63,408
Operating income		116,206			64,891			2,273
Other income (expenses):
Interest		(36,669	)		(9,951	)		(2,945	)
Other		35			2			13
Total other expenses		(36,634	)		(9,949	)		(2,932	)
Income (loss) before income taxes		79,572			54,942			(659	)
Income tax provision(c)		19,150			1,928			470
Consolidated net income (loss)		60,422			53,014			(1,129	)
Less: net income attributable to noncontrolling interest		1,359			—			—
Net income (loss) attributable to stockholders	$	59,063		$	53,014		$	(1,129	)
Net income (loss) per common share:
Basic	$	0.80		$	0.80		$	(0.02	)
Diluted	$	0.80		$	0.78		$	(0.02	)
Weighted average common shares outstanding:
Basic		72,915			66,340			66,340
Diluted		74,771			68,196			66,340
Total production volumes:
Oil (MBbls)		2,682			1,457			556
Natural gas (MMcf)		4,927			3,163			1,017
NGLs (MBbls)		954			595			239
Combined (MBOE)		4,458			2,579			964

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	Year ended December 31,(a)
	2013			2012			2011
	(in thousands, except per share and per unit data)
Average daily production volumes:
Oil (Bbls/D)		7,349			3,981			1,523
Natural gas (Mcf/D)		13,497			8,641			2,786
NGLs (Bbls/D)		2,614			1,625			654
Combined (BOE/D)		12,213			7,047			2,641
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	94.17		$	87.91		$	92.08
Oil ($/Bbl) (after impact of cash settled derivatives)		90.89			87.16			87.16
Natural gas ($/Mcf)		3.37			2.66			3.46
NGLs ($/Bbl)		31.60			34.65			45.96
Combined ($/BOE) (before impact of cash settled derivatives)		67.16			60.92			68.13
Combined ($/BOE) (after impact of cash settled derivatives)		65.18			60.50			65.29
Expenses (per BOE):
Lease operating	$	7.58		$	9.89		$	13.82
Production, severance, and ad valorem taxes		4.27			4.05			4.90
Depletion, depreciation, and amortization		19.56			21.11			20.48
General and administrative		4.79			3.75			8.01
Consolidated Statements of Cash Flows Data:
Cash provided by (used in):
Operating activities	$	183,637		$	95,302		$	18,872
Investing activities		(424,746	)		(347,259	)		(465,475	)
Financing activities		345,263			228,798			471,627
Proved Reserves:
Oil (Bbls)		71,174			49,423			25,972
Natural gas (Mcf)		152,206			103,683			51,560
NGLs (Bbls)		30,722			19,275			11,549
Combined (BOE)		127,264			85,979			46,114
Consolidated Balance Sheets Data:
Cash and cash equivalents	$	113,025		$	8,871		$	32,030
Total assets		1,355,451			852,298			561,823
Long-term debt		500,000			362,000			170,000
Total equity		637,835			420,877			327,452

(a)

In October 2011, we acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas from Element Petroleum, LP for $253.2 million in cash. The operating results of this acquisition are included in our Consolidated Statements of Operations Consolidated Statements of Cash Flows from the date of acquisition forward.

(b)

Holdings was a party to a Services Agreement, dated August 23, 2010, which required Holdings to compensate Apollo Athlon Holdings, L.P. ("Apollo") for consulting and advisory services. Upon the consummation of our IPO, Holdings terminated the Services Agreement and, in connection with the termination, Holdings 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).

(c)

Prior to our corporate reorganization on April 26, 2013, Holdings, our accounting predecessor, was a limited partnership not subject to federal income taxes.

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ITEM 7.    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 in "Item 8. Financial Statements and Supplementary Data". 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 "Item 1A. Risk Factors".

Overview

        We are an independent exploration and production company focused on the acquisition, development, and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin. The Permian Basin spans portions of Texas and New Mexico and consists of three primary sub-basins: the Delaware Basin, the Central Basin Platform, and the Midland Basin. All of our properties are located in the Midland Basin. Our drilling activity is focused on the low-risk vertical development of stacked pay zones, including the Clearfork, Spraberry, Wolfcamp, Cline, Strawn, Atoka, and Mississippian formations, which we refer to collectively as the Wolfberry play, and horizontal development of the Wolfcamp. 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 over 20 years of industry experience and over 10 years of history working together, our founding management has a proven track record of working as a team to acquire, develop, and exploit oil and natural gas reserves in the Permian Basin as well as other resource plays in North America.

        Our acreage position was 127,840 gross (104,059 net) acres at December 31, 2013. During 2013, we drilled 171 gross operated vertical Wolfberry wells and commenced drilling four gross operated horizontal Wolfcamp wells with a 100% success rate. This activity has allowed us to identify and de-risk our multi-year inventory of 4,848 gross (3,908 net) vertical drilling locations, while also identifying 1,065 gross (964 net) horizontal drilling locations in specific areas based on geophysical and technical data, as of December 31, 2013. As we continue to expand our vertical drilling activity to our undeveloped acreage, we expect to identify additional horizontal drilling locations.

        As of December 31, 2013, we had 127 MMBOE of proved reserves, which were 56% oil, 24% NGLs, and 20% natural gas and 37% proved developed. Our PUDs were comprised of 659 gross (632 net) potential vertical drilling locations in our December 31, 2013 reserve report. In addition, we have grown our production to 12,213 BOE/D for 2013.

Initial Public Offering

        On August 7, 2013, we completed our IPO of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $295.7 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".

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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.

Our Acquisition History

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

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

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

Factors That Significantly Affect Our Financial Condition and Results of Operations

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

        We use commodity derivative instruments, such as swaps, 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 "Item 7A. 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

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crude oil at Midland, Texas and thus lowered 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 a portion 2013 to partially mitigate the adverse effects of the widening of the Midland-Cushing WTI differential (the difference between Midland WTI and Cushing WTI).

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

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

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

•

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

•

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

•

facility or equipment availability and unexpected downtime;

•

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

•

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

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

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

        Corporate Reorganization.    We were formed on April 1, 2013. On April 26, 2013, we underwent a corporate reorganization and as a result, Holdings became a majority-owned subsidiary of ours. We operate and control all of Holdings' business and affairs and consolidate its financial results. As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the reorganization transactions had been completed at the beginning of the periods presented or what our future results of operations are likely to be.

        Public Company Expenses.    We now incur direct, incremental general and administrative ("G&A") expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability

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insurance costs, and independent director compensation. 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.    Holdings, our accounting predecessor, is a limited partnership not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations for periods prior to the reorganization transactions because taxable income was passed through to Holdings partners. However, we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings.

        Increased Drilling Activity.    We began operations in January 2011 and gradually added operated vertical drilling rigs. We currently operate eight vertical drilling rigs and one horizontal rig on our properties. Our 2014 drilling capital expenditures are expected to be $595 million, plus an additional $20 million for infrastructure, leasing, and capitalized workovers. We expect to drill 205 gross vertical Wolfberry wells and 21 gross horizontal Wolfcamp wells. We expect to add a second horizontal rig in the second quarter of 2014. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results in each particular year.

        Senior Notes.    In April 2013, we issued $500 million in aggregate principal amount of 7 3/8% senior notes due 2021. We used the proceeds from our senior notes offering to repay a portion of the amounts outstanding under our credit agreement, to repay in full and terminate our second lien term loan, to make a $75 million distribution to Holdings' Class A limited partners, and for general corporate purposes. Our senior notes bear interest at a rate significantly higher than the rates under our credit agreement, which resulted in higher interest expense in periods subsequent to April 2013 as compared to periods prior to April 2013. In the future, we may incur additional indebtedness to fund our acquisition and development activities. Please read "—Capital Commitments, Capital Resources, and Liquidity—Liquidity" for additional discussion of our financing arrangements.

Sources of Our Revenues

        Our revenues are derived from the sale of oil, natural gas, and NGLs within the continental United States and do not include the effects of derivatives. For 2013, oil and NGLs represented approximately 82% 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:

	Year ended December 31,
	2013			2012			2011
Oil
NYMEX WTI High	$	110.53		$	109.77		$	113.93
NYMEX WTI Low		86.68			77.69			75.67
Differential to Average NYMEX WTI		(3.83	)		(6.29	)		(3.03	)
Natural Gas
NYMEX Henry Hub High		4.46			3.90			4.85
NYMEX Henry Hub Low		3.11			1.91			2.99
Differential to Average NYMEX Henry Hub		(0.28	)		(0.13	)		(0.54	)

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        We normally sell production to a relatively small number of customers. In 2013, two purchasers individually accounted for more than 10% of our revenues: High Sierra (46%) and Occidental Petroleum Corporation (27%). If any significant customer decided to stop purchasing oil and natural gas from us, our revenues could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our significant customers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Principal Components of Our Cost Structure

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

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

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

        General and Administrative Expense.    G&A expense consists of company overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, 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.

        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.

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How We Evaluate Our Operations

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

•

Our oil, natural gas, and NGLs revenues increased 91% to $299.4 million in 2013 as compared to $157.1 million in 2012.

•

Our average daily production volumes increased 73% to 12,213 BOE/D in 2013 as compared to 7,047 BOE/D in 2012. Oil and NGLs represented approximately 82% of our total production volumes in 2013.

•

Our average realized oil price increased 7% to $94.17 per Bbl in 2013 as compared to $87.90 per Bbl in 2012. Our average realized natural gas price increased 27% to $3.37 per Mcf in 2013 as compared to $2.66 per Mcf in 2012. However, our average realized NGL price decreased 9% to $31.60 per Bbl in 2013 as compared to $34.65 per Bbl in 2012.

•

Our production margin increased 103% to $246.3 million in 2013 as compared to $121.1 million in 2012. Total wellhead revenues per BOE increased 10% and total production expenses per BOE decreased 15%. On a per BOE basis, our production margin increased 18% to $55.26 per BOE in 2013 as compared to $46.94 per BOE in 2012.

•

We invested $453.2 million in oil and natural gas activities, of which $398.7 million was invested in development and exploration activities and $54.5 million was invested in acquisitions of oil and natural gas properties. We drilled 171 gross (165 net) vertical wells and commenced drilling four gross (four net) horizontal wells, two gross (two net) of which were productive at December 31, 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.

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Results of Operations

Comparison of 2013 to 2012

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

	Year ended December 31,				Increase / (Decrease)
	2013		2012		$			%
Revenues (in thousands):
Oil	$	252,606	$	128,081	$	124,525			97	%
Natural gas		16,620		8,415		8,205			98	%
NGLs		30,147		20,615		9,532			46	%
Total revenues	$	299,373	$	157,111	$	142,262			91	%
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	94.17	$	87.90	$	6.27			7	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	90.89	$	87.16	$	3.73			4	%
Natural gas ($/Mcf)	$	3.37	$	2.66	$	0.71			27	%
NGLs ($/Bbl)	$	31.60	$	34.65	$	(3.05	)		-9	%
Combined ($/BOE) (before impact of cash settled derivatives)	$	67.16	$	60.91	$	6.25			10	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	65.18	$	60.50	$	4.68			8	%
Total production volumes:
Oil (MBbls)		2,682		1,457		1,225			84	%
Natural gas (MMcf)		4,927		3,163		1,764			56	%
NGLs (MBbls)		954		595		359			60	%
Combined (MBOE)		4,458		2,579		1,879			73	%
Average daily production volumes:
Oil (Bbls/D)		7,349		3,981		3,368			85	%
Natural gas (Mcf/D)		13,497		8,641		4,856			56	%
NGLs (Bbls/D)		2,614		1,625		989			61	%
Combined (BOE/D)		12,213		7,047		5,166			73	%

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

	Year ended December 31,
	2013			2012
Average realized oil price ($/Bbl)	$	94.17		$	87.90
Average NYMEX WTI ($/Bbl)	$	98.00		$	94.19
Differential to NYMEX WTI	$	(3.83	)	$	(6.29	)
Average realized oil price to NYMEX WTI percentage		96	%		93	%
Average realized natural gas price ($/Mcf)	$	3.37		$	2.66
Average NYMEX Henry Hub ($/Mcf)	$	3.65		$	2.79
Differential to NYMEX Henry Hub	$	(0.28	)	$	(0.13	)
Average realized natural gas price to NYMEX Henry Hub percentage		92	%		95	%

        Our average realized oil price as a percentage of the average NYMEX WTI price remained relatively constant at 96% for 2013 as compared to 93% for 2012. Our average realized natural gas price as a percentage of the average NYMEX Henry Hub price remained relatively constant at 92% for 2013 as compared to 95% for 2012.

        Oil revenues increased 97% to $252.6 million in 2013 from $128.1 million in 2012 as a result of an increase in our oil production volumes of 1,225 MBbls and a $6.27 per Bbl increase in our average realized oil price. Our higher oil production increased oil revenues by $107.7 million and was primarily the result of our development program in the Permian Basin. Our higher average realized oil price increased oil revenues by $16.8 million and was primarily due to a higher average NYMEX WTI price, which increased to $98.00 per Bbl in 2013 from $94.19 per Bbl in 2012, and the tightening of our oil differentials as previously discussed.

        Natural gas revenues increased 98% to $16.6 million in 2013 from $8.4 million in 2012 as a result of an increase in our natural gas production volumes of 1,764 MMcf and a $0.71 per Mcf increase in our average realized natural gas price. Our higher natural gas production increased natural gas revenues by $4.7 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 was not yet tied into the third-party gathering system, (ii) the pressures on the third-party gathering system were too high to allow additional production from our well to be transported, or (iii) our production was prorated due to high demand on the third-party gathering system. We may flare additional gas from time to time. Our higher average realized natural gas price increased natural gas revenues by $3.5 million and was primarily due to a higher average NYMEX Henry Hub price, which increased to $3.65 per Mcf in 2013 from $2.79 per Mcf in 2012.

        NGL revenues increased 46% to $30.1 million in 2013 from $20.6 million in 2012 as a result of an increase in our NGL production volumes of 359 MBbls, partially offset by a $3.05 per Bbl decrease in our average realized NGL price. Our higher NGL production increased NGL revenues by $12.4 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 $2.9 million.

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

	Year ended December 31,					Increase / (Decrease)
	2013		2012			$			%
Expenses (in thousands):
Production:
Lease operating(a)	$	33,776	$	25,503		$	8,273			32	%
Production, severance, and ad valorem taxes		19,048		10,438			8,610			82	%
Processing, gathering, and overhead		222		84			138			164	%
Total production expenses		53,046		36,025			17,021			47	%
Other:
Depletion, depreciation, and amortization		87,171		54,456			32,715			60	%
General and administrative		21,331		9,678			11,653			120	%
Contract termination fee		2,408		—			2,408			N/A
Acquisition costs		421		876			(455	)		-52	%
Derivative fair value loss (gain)		18,115		(9,293	)		27,408			-295	%
Accretion of discount on asset retirement obligations		675		478			197			41	%
Total operating		183,167		92,220			90,947			99	%
Interest		36,669		9,951			26,718			268	%
Income tax provision		19,150		1,928			17,222			893	%
Total expenses	$	238,986	$	104,099		$	134,887			130	%
Expenses (per BOE):
Production:
Lease operating(a)	$	7.58	$	9.89		$	(2.31	)		-23	%
Production, severance, and ad valorem taxes		4.27		4.05			0.22			5	%
Processing, gathering, and overhead		0.05		0.03			0.02			67	%
Total production expenses		11.90		13.97			(2.07	)		-15	%
Other:
Depletion, depreciation, and amortization		19.56		21.11			(1.55	)		-7	%
General and administrative		4.79		3.75			1.04			28	%
Contract termination fee		0.54		—			0.54			N/A
Acquisition costs		0.09		0.34			(0.25	)		-74	%
Derivative fair value loss (gain)		4.06		(3.60	)		7.66			-213	%
Accretion of discount on asset retirement obligations		0.15		0.19			(0.04	)		-21	%
Total operating		41.09		35.76			5.33			15	%
Interest		8.23		3.86			4.37			113	%
Income tax provision		4.30		0.75			3.55			473	%
Total expenses	$	53.62	$	40.37		$	13.25			33	%

(a)

Includes non-cash equity-based compensation of $453,000 ($0.10 per BOE) and $29,000 ($0.01 per BOE) for 2013 and 2012, respectively.

        Production expenses.    LOE increased 32% to $33.8 million in 2013 from $25.5 million in 2012 as a result of an increase in production volumes from wells drilled, which contributed $18.6 million of additional LOE, partially offset by a $2.31 decrease in the average LOE per BOE rate, which would have reduced LOE by $10.3 million if production had been unchanged. The decrease in our average

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

        Production, severance, and ad valorem taxes increased 82% to $19.0 million in 2013 from $10.4 million in 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 2013 as compared to 6.6% in 2012 primarily due to an increase in the number of wells brought on production in 2013 as compared to 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 60% to $87.2 million in 2013 from $54.5 million in 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 120% to $21.3 million in 2013 from $9.7 million in 2012 primarily due to (i) cash bonuses, (ii) $1.0 million of non-cash equity-based compensation related to the accelerated vesting of the Class B limited partner interests in Holdings as a result of the IPO, (iii) nonrecurring corporate reorganization costs related to the transition from a partnership to a corporation of $0.6 million, (iv) higher payroll and payroll-related costs as we continue to add employees in order to manage our growing asset base, and (v) additional expenses related to being a public company.

        Contract termination fee.    Holdings was a party to a Services Agreement, dated August 23, 2010, which required Holdings to compensate Apollo for consulting and advisory services. Upon the consummation of our IPO, Holdings terminated the Services Agreement and, in connection with the termination, Holdings 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 2013, we recorded an $18.1 million derivative fair value loss as compared to a $9.3 million derivative fair value gain in 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. The change from a derivative fair value gain to a derivative fair value loss was primarily due to a higher average NYMEX WTI price in 2013 as compared to 2012 and an increase in the future oil price outlook during 2013, which negatively impacted the fair values of our oil swaps. Included in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums during 2013 of $8.8 million as compared to $1.1 million during 2012.

        Interest expense.    Interest expense increased 268% to $36.7 million in 2013 from $10.0 million in 2012 due to higher long-term debt balances and higher borrowing costs in 2013 when compared to 2012. Our weighted-average total debt was $485.8 million for 2013 as compared to $263.4 million for 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, (ii) various acquisitions of oil and natural gas properties, and (iii) a $75 million distribution to Holdings' 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 7.6% for 2013 as compared to 4.3% for 2012. This increase in borrowing cost was primarily due to the issuance of our senior notes, a portion of the net

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proceeds from which were used to substantially pay down outstanding borrowings on our credit agreement that were subject to lower interest rates than our senior notes. Our weighted-average interest expense for 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 our 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:

	Year ended December 31,
							Increase / (Decrease)
	2013			2012
	(in thousands)
Credit agreement	$	3,449		$	5,932		$	(2,483	)
Senior notes		26,104			—			26,104
Former second lien term loan		2,777			3,081			(304	)
Write off of debt issuance costs		2,838			444			2,394
Amortization of debt issuance costs		1,844			713			1,131
Less: interest capitalized		(343	)		(219	)		(124	)
Total	$	36,669		$	9,951		$	26,718

        Income taxes.    In 2013, we recorded an income tax provision of $19.2 million as compared to $1.9 million in 2012. In 2013, we had income before income taxes and noncontrolling interest of $79.6 million as compared to $54.9 million in 2012. Our effective tax rate increased to 24.1% in 2013 as compared to 3.5% in 2012 as a result of our corporate reorganization on April 26, 2013 in which Athlon (a C-corporation) obtained most of the interests in Holdings. Prior to April 26, 2013, Holdings, our accounting predecessor, was a limited partnership not subject to federal income taxes.

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Comparison of 2012 to 2011

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

	Year ended December 31,				Increase / (Decrease)
	2012		2011		$			%
Revenues (in thousands):
Oil	$	128,081	$	51,193	$	76,888			150	%
Natural gas		8,415		3,521		4,894			139	%
NGLs		20,615		10,967		9,648			88	%
Total revenues	$	157,111	$	65,681	$	91,430			139	%
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	87.90	$	92.08	$	(4.18	)		-5	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	87.16	$	87.16	$	—			0	%
Natural gas ($/Mcf)	$	2.66	$	3.46	$	(0.80	)		-23	%
NGLs ($/Bbl)	$	34.65	$	45.96	$	(11.31	)		-25	%
Combined ($/BOE) (before impact of cash settled derivatives)	$	60.91	$	68.13	$	(7.22	)		-11	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	60.50	$	65.29	$	(4.79	)		-7	%
Total production volumes:
Oil (MBbls)		1,457		556		901			162	%
Natural gas (MMcf)		3,163		1,017		2,146			211	%
NGLs (MBbls)		595		239		356			149	%
Combined (MBOE)		2,579		964		1,615			168	%
Average daily production volumes:
Oil (Bbls/D)		3,981		1,523		2,458			161	%
Natural gas (Mcf/D)		8,641		2,786		5,855			210	%
NGLs (Bbls/D)		1,625		654		971			148	%
Combined (BOE/D)		7,047		2,641		4,406			167	%

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

	Year Ended December 31,
	2012			2011
Average realized oil price ($/Bbl)	$	87.90		$	92.08
Average NYMEX WTI ($/Bbl)	$	94.19		$	95.11
Differential to NYMEX WTI	$	(6.29	)	$	(3.03	)
Average realized oil price to NYMEX WTI percentage		93	%		97	%
Average realized natural gas price ($/Mcf)	$	2.66		$	3.46
Average NYMEX Henry Hub ($/Mcf)	$	2.79		$	4.00
Differential to NYMEX Henry Hub	$	(0.13	)	$	(0.54	)
Average realized natural gas price to NYMEX Henry Hub percentage		95	%		87	%

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        Our average realized oil price as a percentage of the average NYMEX WTI price was 93% for 2012 as compared to 97% for 2011. All of our oil contracts include the Midland-Cushing differential, which widened in 2012 due to difficulty transporting oil production from the Permian Basin to the Gulf Coast refineries as a result of lack of logistics and infrastructure. 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% to $128.1 million in 2012 from $51.2 million in 2011 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% to $8.4 million in 2012 from $3.5 million in 2011 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% to $20.6 million in 2012 from $11.0 million in 2011 as a result of an increase in our NGL production volumes of 356 MBbls, partially offset by an $11.31 per Bbl decrease in our average realized NGL price. Our higher NGL production increased NGL revenues by $16.4 million and was primarily the result of a full year of production from our Element acquisition in October 2011, as well as our development program in the Permian Basin. The properties initially acquired from Element contributed approximately 50 MBbls ($1.5 million in revenue) of additional NGL production in 2012 as compared to 2011 while our development program contributed approximately 306 MBbls ($14.9 million in revenue) of additional NGL production. Our lower average realized NGL price decreased NGL revenues by $6.7 million and was primarily due to increased supplies of NGLs from NGL-rich shales in the Permian Basin and other basins including the Eagle Ford and the Williston.

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

	Year ended December 31,					Increase / (Decrease)
	2012			2011		$			%
Expenses (in thousands):
Production:
Lease operating(a)	$	25,503		$	13,328	$	12,175			91	%
Production, severance, and ad valorem taxes		10,438			4,727		5,711			121	%
Processing, gathering, and overhead		84			60		24			40	%
Total production expenses		36,025			18,115		17,910			99	%
Other:
Depletion, depreciation, and amortization		54,456			19,747		34,709			176	%
General and administrative		9,678			7,724		1,954			25	%
Acquisition costs		876			9,519		(8,643	)		-91	%
Derivative fair value loss (gain)		(9,293	)		7,959		(17,252	)		-217	%
Accretion of discount on asset retirement obligations		478			344		134			39	%
Total operating		92,220			63,408		28,812			45	%
Interest		9,951			2,945		7,006			238	%
Income tax provision		1,928			470		1,458			310	%
Total expenses	$	104,099		$	66,823	$	37,276			56	%
Expenses (per BOE):
Production:
Lease operating(a)	$	9.89		$	13.82	$	(3.93	)		-28	%
Production, severance, and ad valorem taxes		4.05			4.90		(0.85	)		-17	%
Processing, gathering, and overhead		0.03			0.06		(0.03	)		-50	%
Total production expenses		13.97			18.78		(4.81	)		-26	%
Other:
Depletion, depreciation, and amortization		21.11			20.48		0.63			3	%
General and administrative		3.75			8.01		(4.26	)		-53	%
Acquisition costs		0.34			9.87		(9.53	)		-97	%
Derivative fair value loss (gain)		(3.60	)		8.26		(11.86	)		-144	%
Accretion of discount on asset retirement obligations		0.19			0.36		(0.17	)		-47	%
Total operating		35.76			65.76		(30.00	)		-46	%
Interest		3.86			3.05		0.81			27	%
Income tax provision		0.75			0.49		0.26			53	%
Total expenses	$	40.37		$	69.30	$	(28.93	)		-42	%

(a)

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

        Production expenses.    LOE increased 91% to $25.5 million in 2012 from $13.3 million in 2011 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 LOE 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

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through 2012 infrastructure projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of water.

        Production, severance and ad valorem taxes increased 121% to $10.4 million in 2012 from $4.7 million in 2011 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.

        DD&A expense.    DD&A expense increased 176% to $54.5 million in 2012 from $19.7 million in 2011 primarily due to a full year of production from the properties acquired from Element 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 25% to $9.7 million in 2012 from $7.7 million in 2011 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 91% to $0.9 million in 2012 from $9.5 million in 2011. 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 238% to $9.9 million in 2012 from $2.9 million in 2011 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 total debt was $263.4 million for 2012 as compared to $78.4 million for 2011. Our weighted-average interest rate for total indebtedness was 4.3% for 2012 as compared to 3.8% for 2011. Our weighted-average outstanding borrowings increased in 2012 in order to fund the closing of the Element acquisition in October 2011 and our higher level of development and exploration activities during 2012.

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

	Year ended December 31,
						Increase / (Decrease)
	2012			2011
	(in thousands)
Credit agreement	$	5,932		$	2,387	$	3,545
Former second lien term loan		3,081			—		3,081
Write off of debt issuance costs		444			—		444
Amortization of debt issuance costs and deferred premiums		713			558		155
Less: interest capitalized		(219	)		—		(219	)
Total	$	9,951		$	2,945	$	7,006

Capital Commitments, Capital Resources, and Liquidity

Capital commitments

        Our primary uses of cash are:

•

Development and exploration of oil and natural gas properties;

•

Acquisitions of oil and natural gas properties;

•

Funding of working capital; and

•

Contractual obligations.

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

	Year ended December 31,
	2013		2012		2011
	(in thousands)
Development(a)	$	180,011	$	201,174	$	71,403
Exploration(b)		218,680		75,008		17,829
Total	$	398,691	$	276,182	$	89,232

(a)

Includes asset retirement obligations incurred of $609,000, $606,000, and $108,000 during 2013, 2012, and 2011, respectively.

(b)

Includes asset retirement obligations incurred of $404,000, $209,000, and $58,000 during 2013, 2012, and 2011, respectively.

        Our development capital primarily relates to the drilling of development and infill wells, workovers of existing wells, and the construction of field related facilities. Our development capital for 2013 yielded 71 gross (70 net) vertical wells and no dry holes.

        Our exploration expenditures primarily relate to the drilling of exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. Our exploration capital for the 2013 yielded 100 gross (95 net) vertical wells and no dry holes. We also commenced drilling four gross (four net) horizontal wells, two gross (two net) of which were productive at December 31, 2013.

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        Our development and exploration activities in 2013 were higher than in 2012 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 2014, we expect our drilling capital expenditures to be $595 million, plus an additional $20 million for leasing, infrastructure, and capital workovers, and we expect to drill 205 gross vertical Wolfberry wells and 21 gross horizontal Wolfcamp wells.

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

	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Acquisitions of proved properties(a)	$	19,609	$	42,122	$	287,400
Acquisitions of unproved properties		34,922		38,908		130,273
Total	$	54,531	$	81,030	$	417,673

(a)

Includes asset retirement obligations incurred of $395,000, $60,000, and $3.3 million during 2013, 2012, and 2011, respectively.

        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 December 31, 2013 and 2012, our working capital (defined as total current assets less total current liabilities) was a $45.4 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 that our cash on hand, cash flows from operating activities, and availability under our credit agreement will be sufficient to fund our working capital needs, capital expenditures, and other obligations for at least the next 12 months. We expect that our production volumes, commodity prices, and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

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        Contractual obligations.    The following table provides our contractual obligations and commitments as of December 31, 2013:

	Payments Due by Period
Contractual Obligations and Commitments	Total		2014		2015 - 2016		2017 - 2018		Thereafter
	(in thousands)
Credit agreement(a)	$	—	$	—	$	—	$	—	$	—
Senior notes(a)		776,563		36,875		73,750		73,750		592,188
Commodity derivative contracts(b)		8,354		8,354		—		—		—
Development commitments(c)		68,059		68,059		—		—		—
Operating leases and commitments(d)		1,316		467		849		—		—
Asset retirement obligations(e)		40,710		60		—		—		40,650
Total	$	895,002	$	113,815	$	74,599	$	73,750	$	632,838

(a)

Includes principal and projected interest payments. As of December 31, 2013, there were no outstanding borrowings under our credit agreement. Please read "—Liquidity" for additional information regarding our long-term debt.

(b)

Represents net liabilities for our commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. As of December 31, 2013, the fair value of our 2015 commodity derivative contracts was a net asset of $2.3 million. Please read "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" for additional information regarding our commodity derivative contracts.

(c)

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

(d)

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

(e)

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

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

Capital resources

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

	Year ended December 31,
	2013			2012			2011
	(in thousands)
Net cash provided by operating activities	$	183,637		$	95,302		$	18,872
Net cash used in investing activities		(424,746	)		(347,259	)		(465,475	)
Net cash provided by financing activities		345,263			228,798			471,627
Net increase (decrease) in cash	$	104,154		$	(23,159	)	$	25,024

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        Cash flows from operating activities.    Cash provided by operating activities increased $88.3 million to $183.6 million in 2013 from $95.3 million in 2012, primarily due to an increase in our production margin due to a 73% 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 2013 as compared to 2012.

        Cash provided by operating activities increased $76.4 million to $95.3 million in 2012 from $18.9 million in 2011, 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 $77.5 million to $424.7 million in 2013 from $347.3 million in 2012 due to a $103.7 million increase in amounts paid to develop oil and natural gas properties, partially offset by a $26.5 million decrease in amounts paid to acquire oil and natural gas properties. 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 to $347.3 million in 2012 from $465.5 million in 2011, primarily due to a $334.2 million decrease in amounts paid to acquire oil and natural gas properties, which in 2011 included our SandRidge and Element acquisitions, partially offset by a $208.8 million increase in amounts paid to develop oil and natural gas properties as we utilized at least six rigs for the majority of 2012. In January 2011, we terminated certain oil puts that were in place at December 31, 2010 and received net proceeds of $7.6 million, which are included in cash used in investing activities for 2011.

        Cash flows from financing activities.    Our cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and issuances of shares of our common stock. We periodically draw on our credit agreement to fund acquisitions and other capital commitments.

        During 2013, we received net cash of $345.3 million from financing activities, including $295.7 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, repayments of $237 million under our credit agreement, and a $75 million distribution to Holdings' Class A limited partners. Repayments reduced the outstanding borrowings under our credit agreement from $237 million at December 31, 2012 to none at December 31, 2013.

        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, 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 borrowings of $170 million under our credit agreement and $304.0 million of partner contributions.

Liquidity

        Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our credit agreement. Since we operate a majority of our wells, we 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,

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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 additional capital to develop our entire inventory of identified drilling locations should we elect to do so.

        In 2014, we expect our drilling capital expenditures to be $595 million, plus an additional $20 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 flows 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 2013, our average realized oil and natural gas prices increased by 7% and 27%, respectively, as compared to 2012, while our average realized NGL price decreased by 9%. 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. Currently, our hedged oil volumes for 2014 and 2015 represented 105% and 31%, respectively, of our fourth quarter of 2013 oil production at weighted average prices of $92.61 per Bbl and $91.74 per Bbl, respectively. An increase in oil prices above the ceiling prices in our commodity derivative contracts would limit 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 "Item 7A. 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 our senior notes offering 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. In November 2013, we amended our credit agreement to, among other things, increase the borrowing base to $525 million. As of December 31, 2013, the borrowing

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base was $525 million and there were no outstanding borrowings and no outstanding letters of credit under our credit agreement. As of March 7, 2014, there were $30 million 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 (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 our credit agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under our credit agreement bear interest at the base rate plus the applicable margin indicated in the following table. We also incur a quarterly commitment fee on the unused portion of our credit agreement indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	Unused Commitment Fee			Applicable Margin for Eurodollar Loans			Applicable Margin for Base Rate Loans
Less than or equal to .30 to 1		0.375	%		1.50	%		0.50	%
Greater than .30 to 1 but less than or equal to .60 to 1		0.375	%		1.75	%		0.75	%
Greater than .60 to 1 but less than or equal to .80 to 1		0.50	%		2.00	%		1.00	%
Greater than .80 to 1 but less than or equal to .90 to 1		0.50	%		2.25	%		1.25	%
Greater than .90 to 1		0.50	%		2.50	%		1.50	%

        The "Eurodollar rate" for any interest period (either one, two, three, or nine 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: (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 our credit agreement. Borrowings under our credit agreement may be repaid from time to time without penalty.

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

•

a prohibition against incurring debt, subject to permitted exceptions;

•

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

•

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

•

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

•

a requirement that we maintain a ratio of consolidated total debt to EBITDAX (as defined in our credit agreement) of not more than 4.75 to 1.0 (which ratio changes to 4.5 to 1.0 beginning with the quarter ending June 30, 2014); and

•

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

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        Our credit agreement contains customary events of default, including our failure to comply with 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 our credit agreement to be immediately due and payable, which would materially and adversely affect our financial condition and liquidity.

        Certain of the lenders under our credit agreement are also counterparties to our commodity derivative contracts. Please read "Item 7A. 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 our 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 Holdings' Class A limited partners, and for general corporate purposes.

        The indenture governing the senior notes contains covenants, including, among other things, covenants that restrict our ability to:

•

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

•

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

•

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

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

        Under the indenture, starting on April 15, 2016, we will be able to redeem some or all of the senior notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption. Prior to April 15, 2016, we will be able, at our option, to redeem up to 35% of the aggregate principal amount of the senior notes at a price of 107.375% of the principal thereof, plus accrued and unpaid interest to the date of redemption, with an amount equal to the net proceeds from certain equity offerings. In addition, at our option, prior to April 15, 2016, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes, plus an "applicable premium", plus accrued and unpaid interest to the date of redemption. If a change of control occurs on or prior to July 15, 2014, we may redeem all, but not less than all, of the notes at 110% of the principal amount thereof plus accrued and unpaid interest to, but not including, the redemption date. Certain asset dispositions will be triggering events that may require us to repurchase all or any part of a noteholder's notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, up 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 December 31, 2013, we had total assets of $1.4 billion and total capitalization of $1.1 billion, of which 56% was represented by equity and 44% 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

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equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Changes in Prices

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

	Year ended December 31,
	2013		2012		2011
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	94.17	$	87.90	$	92.08
Oil ($/Bbl) (after impact of cash settled derivatives)		90.89		87.16		87.16
Natural gas ($/Mcf)		3.37		2.66		3.46
NGLs ($/Bbl)		31.60		34.65		45.96
Combined ($/BOE) (before impact of cash settled derivatives)		67.16		60.91		68.13
Combined ($/BOE) (after impact of cash settled derivatives)		65.18		60.50		65.29

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

Critical Accounting Policies and Estimates

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

Oil and Natural Gas Reserves

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

•

quality and quantity of available data;

•

interpretation of that data;

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•

accuracy of various mandated economic assumptions; and

•

judgment of the independent reserve engineer.

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

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

Method of Accounting for Oil and Natural Gas Properties

        We apply the provisions of the "Extractive Activities—Oil and Gas" topic of the FASB's 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 unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated 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 unevaluated 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 properties are included in the full cost pool as incurred; otherwise, they are allocated to various unevaluated 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.

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        We capitalize interest on expenditures made in connection with exploratory 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.

Impairment

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

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

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

Asset Retirement Obligations

        We apply the provisions of the "Asset Retirement and Environmental Obligations" topic of the ASC. We have obligations as a result of lease agreements and enacted laws to remove our equipment and restore land at the end of production operations. These asset retirement obligations are primarily associated with plugging and abandoning wells and land remediation. At the time a drilled well is completing or a well is 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.

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        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.

Revenue Recognition

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

Derivatives

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

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

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

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

        As required by GAAP, we utilize the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities. Fair values of swaps are estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services. 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: (i) current market and contractual prices for the underlying instruments; (ii) quoted forward prices for

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oil; (iii) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (iv) appropriate volatilities.

        We adjust the valuations from the valuation model for nonperformance risk. For commodity derivative contracts which are in an asset position, we add the counterparty's credit default swap spread to the risk-free rate. If a counterparty does not have a credit default swap spread, we use other companies with similar credit ratings to determine the applicable spread. For commodity derivative contracts which are in a liability position, we use the yield on our senior notes less the risk-free rate.

        Please read "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our commodity derivative contracts.

Income Taxes

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

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

        In April 2013, we effected a corporate reorganization. Holdings, 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 Holdings were exchanged for shares of our common stock. Our operations are now subject to federal income tax. The tax implications of the corporate reorganization and the tax impact of the conversion to operating as a taxable entity have been reflected in our consolidated financial statements.

New Accounting Pronouncements

        In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities" and in January 2013 issued ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities". These ASUs created new disclosure requirements regarding the nature of an entity's rights of offset and related arrangements associated with its derivative instruments, repurchase agreements, and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements are required, irrespective of whether the entity has elected to offset those instruments in the balance sheet. These ASUs were effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs did not impact our financial condition, results of operations, or liquidity.

Emerging Growth Company

        The JOBS Act permits an "emerging growth company" like us to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies.

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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.

Cautionary Note Regarding Forward-Looking Statements

        This Report 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 Report, are forward-looking statements. When used in this Report, the words "could", "should", "believe", "anticipate", "intend", "estimate", "expect", "may", "continue", "predict", "plan", "potential", "project", "forecast", and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

        Forward-looking statements may include statements about:

•

our business strategy;

•

our estimated reserves and the present value thereof;

•

our technology;

•

our cash flows and liquidity;

•

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

•

realized commodity prices;

•

timing and amount of future production of reserves;

•

availability of drilling and production equipment;

•

availability of pipeline capacity;

•

availability of oilfield labor;

•

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

•

availability and terms of capital;

•

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

•

government regulations;

•

marketing of production;

•

exploitation or property acquisitions;

•

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

•

general economic and business conditions;

•

competition in the oil and natural gas industry;

•

effectiveness of our risk management activities;

•

environmental and other liabilities;

•

counterparty credit risk;

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•

taxation of the oil and natural gas industry;

•

developments in other countries that produce oil and natural gas;

•

uncertainty regarding future operating results;

•

plans and objectives of management or the Apollo Funds; and

•

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

        All forward-looking statements speak only as of the date of this Report. 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 Report 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 "Item 1A. Risk Factors" and elsewhere in this Report. These factors include, but are not limited to risks related to:

•

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

•

uncertainties about our estimated reserves;

•

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

•

general economic and business conditions;

•

risks associated with negative developments in the capital markets;

•

failure to realize expected value creation from property acquisitions;

•

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

•

drilling results;

•

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

•

potential adoption of new governmental regulations;

•

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

•

risks associated with our substantial indebtedness; and

•

our ability to satisfy future cash obligations and environmental costs.

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

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

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Derivative policy

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

Counterparties

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

Counterparty	Fair Market Value of Oil Derivative Contracts Committed
	(in thousands)
BNP Paribas	$	1,082

        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 our 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: (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 our credit exposure to a given counterparty in the event of close-out.

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

Commodity price sensitivity

        Commodity prices are often subject to significant volatility due to many factors that are beyond our control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. We manage oil price risk with swaps, which provide a fixed price for a notional amount of

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sales volumes. The following table summarizes our open commodity derivative contracts as of December 31, 2013:

Period	Average Daily Swap Volume		Weighted- Average Swap Price		Asset (Liability) Fair Market Value
	(Bbl)		(per Bbl)		(in thousands)
2014		7,950	$	92.67	$	(8,354	)
2015		1,300		93.18		2,330
					$	(6,024	)

        As of December 31, 2013, the fair market value of our oil derivative contracts was a net liability of $6.0 million. Based on our open commodity derivative positions at December 31, 2013, a 10% increase in the NYMEX WTI price would increase our net commodity derivative liability by approximately $31.1 million, while a 10% decrease in the NYMEX WTI price would change our net commodity derivative liability to a net commodity derivative asset of approximately $25.1 million.

Interest rate sensitivity

        At December 31, 2013, we had outstanding debt of $500 million, all of which bears interest at a fixed rate of 7³/8%. At December 31, 2013, the fair value of our senior notes was approximately $522.8 million.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		85
Consolidated Balance Sheets as of December 31, 2013 and 2012		86
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012, and 2011		87
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2013, 2012, and 2011		88
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012, and 2011		89
Notes to Consolidated Financial Statements		90
Supplementary Information		117

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of
Athlon Energy Inc.

        We have audited the accompanying consolidated balance sheets of Athlon Energy Inc. (the "Company") (formerly, "Athlon Holdings LP") as of December 31, 2013 and 2012, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Fort Worth, Texas
March 7, 2014

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CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share amounts)

	December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	113,025		$	8,871
Accounts receivable		48,238			24,501
Derivatives, at fair value		—			2,246
Inventory		928			1,022
Deferred taxes		380			—
Other		1,166			2,486
Total current assets		163,737			39,126
Oil and natural gas properties and equipment, at cost—full cost method:
Evaluated, including wells and related equipment		1,244,178			788,571
Unevaluated		89,859			89,860
Accumulated depletion, depreciation, and amortization		(160,779	)		(73,824	)
		1,173,258			804,607
Derivatives, at fair value		2,330			2,854
Debt issuance costs		14,679			4,418
Other		1,447			1,293
Total assets	$	1,355,451		$	852,298
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	459		$	3,170
Affiliate		—			935
Accrued liabilities:
Lease operating		6,563			3,858
Production, severance, and ad valorem taxes		2,550			1,307
Development capital		68,059			39,483
Interest		7,790			834
Derivatives, at fair value		8,354			592
Revenue payable		20,513			9,330
Deferred taxes		—			58
Other		4,035			1,808
Total current liabilities		118,323			61,375
Derivatives, at fair value		—			519
Asset retirement obligations, net of current portion		6,795			5,049
Long-term debt		500,000			362,000
Deferred taxes		92,397			2,340
Other		101			138
Total liabilities		717,616			431,421
Commitments and contingencies
Equity:
Partners' equity		—			420,877
Preferred stock, $.01 par value, at December 31, 2013, 50,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, at December 31, 2013, 500,000,000 shares authorized, 82,129,089 issued and outstanding		821			—
Additional paid-in capital		593,943			—
Retained earnings		32,283			—
Total stockholders' equity		627,047			—
Noncontrolling interest		10,788			—
Total equity		637,835			420,877
Total liabilities and equity	$	1,355,451		$	852,298

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

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CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

	Year Ended December 31,
	2013			2012			2011
Revenues:
Oil	$	252,606		$	128,081		$	51,193
Natural gas		16,620			8,415			3,521
Natural gas liquids		30,147			20,615			10,967
Total revenues		299,373			157,111			65,681
Expenses:
Production:
Lease operating		33,776			25,503			13,328
Production, severance, and ad valorem taxes		19,048			10,438			4,727
Processing, gathering, and overhead		222			84			60
Depletion, depreciation, and amortization		87,171			54,456			19,747
General and administrative		21,331			9,678			7,724
Contract termination fee		2,408			—			—
Acquisition costs		421			876			9,519
Derivative fair value loss (gain)		18,115			(9,293	)		7,959
Accretion of discount on asset retirement obligations		675			478			344
Total expenses		183,167			92,220			63,408
Operating income		116,206			64,891			2,273
Other income (expenses):
Interest		(36,669	)		(9,951	)		(2,945	)
Other		35			2			13
Total other expenses		(36,634	)		(9,949	)		(2,932	)
Income (loss) before income taxes		79,572			54,942			(659	)
Income tax provision		19,150			1,928			470
Consolidated net income (loss)		60,422			53,014			(1,129	)
Less: net income attributable to noncontrolling interest		1,359			—			—
Net income (loss) attributable to stockholders	$	59,063		$	53,014		$	(1,129	)
Net income (loss) per common share:
Basic	$	0.80		$	0.80		$	(0.02	)
Diluted	$	0.80		$	0.78		$	(0.02	)
Weighted average common shares outstanding:
Basic		72,915			66,340			66,340
Diluted		74,771			68,196			66,340

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

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

				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, 2010	$	24,499			—	$	—	$	—		$	—	$	—		$	—	$	24,499
Capital contributions		303,976			—		—		—			—		—			—		303,976
Equity-based compensation		106			—		—		—			—		—			—		106
Net loss		(1,129	)		—		—		—			—		—			—		(1,129	)
Balance at December 31, 2011		327,452			—		—		—			—		—			—		327,452
Capital contributions		40,166			—		—		—			—		—			—		40,166
Equity-based compensation		245			—		—		—			—		—			—		245
Net income		53,014			—		—		—			—		—			—		53,014
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		—			—		—		(71,605	)		—		(71,605	)		—		(71,605	)
Shares of common stock sold in initial public offering, net of offering costs		—			15,789		158		295,498			—		295,656			—		295,656
Equity-based compensation subsequent to corporate reorganization		—			—		—		5,896			—		5,896			—		5,896
Consolidated net income subsequent to corporate reorganization		—			—		—		—			32,283		32,283			1,359		33,642
Balance at December 31, 2013	$	—			82,129	$	821	$	593,943		$	32,283	$	627,047		$	10,788	$	637,835

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

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ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Consolidated net income (loss)	$	60,422		$	53,014		$	(1,129	)
Adjustments to reconcile consolidated net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		87,171			54,456			19,747
Deferred taxes		18,015			1,928			470
Non-cash derivative loss (gain)		10,013			(9,947	)		7,509
Equity-based compensation		5,307			152			106
Other		5,575			1,758			963
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(24,534	)		(7,320	)		(16,963	)
Other current assets		(71	)		(337	)		(1,691	)
Other assets		—			—			(16	)
Accounts payable		(2,583	)		(2,140	)		537
Accrued interest		6,956			578			256
Revenue payable		10,681			3,620			5,710
Derivatives		—			—			(1,950	)
Other current liabilities		6,685			(460	)		5,323
Net cash provided by operating activities		183,637			95,302			18,872
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(54,136	)		(80,602	)		(414,759	)
Development of oil and natural gas properties		(369,946	)		(266,235	)		(57,457	)
Monetization of put options		—			—			7,625
Other		(664	)		(422	)		(884	)
Net cash used in investing activities		(424,746	)		(347,259	)		(465,475	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		628,992			519,672			198,651
Payments on long-term debt		(505,926	)		(331,000	)		(31,000	)
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		295,697			—			—
Capital contributions		1,500			40,166			303,976
Other		—			(40	)		—
Net cash provided by financing activities		345,263			228,798			471,627
Increase (decrease) in cash and cash equivalents		104,154			(23,159	)		25,024
Cash and cash equivalents, beginning of period		8,871			32,030			7,006
Cash and cash equivalents, end of period	$	113,025		$	8,871		$	32,030

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Formation of the Company and Description of Business

        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 $71.6 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, L.P. ("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") and Holdings' management team and certain employees owned all of the Class A limited partner interests in Holdings and 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 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.

Initial Public Offering

        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 $295.7 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". 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 (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.

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Note 2. Summary of Significant Accounting Policies

Principles of Consolidation

        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.

Use of Estimates

        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

        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:

	Year ended December 31,
	2013		2012		2011
	(in thousands)
Cash paid during the period for:
Interest	$	25,220	$	8,326	$	2,395
Income taxes		—		—		—

Accounts Receivable

        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, 2013 and 2012, Athlon did not have an allowance for doubtful accounts.

Inventory

        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

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Note 2. Summary of Significant Accounting Policies (Continued)

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:

	December 31,
	2013		2012
	(in thousands)
Materials and supplies	$	429	$	670
Oil inventory		499		352
Total inventory	$	928	$	1,022

Oil and Natural Gas Properties

        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 unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated 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 unevaluated 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 properties are included in the full cost pool as incurred; otherwise, they are allocated to various unevaluated leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

        Independent petroleum engineers estimate Athlon's proved reserves annually as of 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.

        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.

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Note 2. Summary of Significant Accounting Policies (Continued)

        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.

        Athlon capitalizes interest on expenditures made in connection with exploratory 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 2013 and 2012, Athlon capitalized approximately $0.3 million and $0.2 million, respectively, of interest expense. During 2011, Athlon did not capitalize any 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 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 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 therefore has 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2. Summary of Significant Accounting Policies (Continued)

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

	December 31,
	2013		2012
	(in thousands)
Evalauted leasehold costs	$	448,689	$	376,271
Wells and related equipment—completed		748,900		379,036
Wells and related equipment—in process		46,589		33,264
Total evaluated	$	1,244,178	$	788,571

Asset Retirement Obligations

        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 drilled well is completing or a well is 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.

        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, 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.

Equity-Based Compensation

        Athlon accounts for equity-based compensation according to the "Share-Based Payment" topic of the ASC, which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. Please read "Note 9. Employee Benefit Plans" for additional discussion of Athlon's employee benefit plans.

        The "Share-Based Payment" topic of the ASC also requires that the benefits associated with the tax deductions in excess of recognized compensation cost, if any, be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. Athlon recognizes compensation costs related to awards with graded vesting on a straight-line basis over the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2. Summary of Significant Accounting Policies (Continued)

requisite service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

Segment Reporting

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

Major Customers / Concentration of Credit Risk

        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:

	Percentage of Total Revenues for the Year Ended December 31,									Outstanding Accounts Receivable Balance as of December 31,
Purchaser	2013			2012			2011			2013			2012
										(in thousands)
Occidental Petroleum Corporation		27	%		29	%		58	%	$	11,673		$	4,456
DCP Midstream			(a)		12	%		13	%			(a)		2,604
High Sierra Crude Oil & Marketing, LLC(b)		46	%		43	%		13	%		18,951			9,348

(a)

Less than 10% for the period indicated.

(b)

Formerly Pecos Gathering & Marketing.

Income Taxes

        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 effected a corporate reorganization. Holdings, Athlon's accounting predecessor, is a partnership not subject to federal income tax. Pursuant to 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

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Note 2. Summary of Significant Accounting Policies (Continued)

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.

Revenue Recognition

        Revenues from the sale of oil, natural gas, and NGLs are recognized when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller's price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured. Because final settlement of our hydrocarbon sales can take up to two months, sales volumes and prices are estimated and accrued using information available at the time the revenue is recorded. 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, 2013 and 2012, 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 insignificant.

Derivatives

        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 under Athlon's credit agreement.

        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 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.

Noncontrolling Interest

        As of December 31, 2013, management and certain employees owned approximately 2.2% of Holdings. Athlon owns 100% of Athlon Holdings GP LLC, which is Holdings' general partner.

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Note 2. Summary of Significant Accounting Policies (Continued)

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 December 31, 2013 of approximately $10.8 million represents management and certain 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 attributable to noncontrolling interest" for 2013 of approximately $1.4 million represents the net income of Holdings attributable to management and certain 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 2013 (in thousands):

Net income attributable to stockholders	$	59,063
Transfer from noncontrolling interest:
Increase in Athlon's paid-in capital for corporate reorganization		292,549
Increase in Athlon's paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering		295,498
Net transfer from noncontrolling interest		588,047
Change from net income attributable to stockholders and transfers from noncontrolling interest	$	647,110

Earnings Per Share

        For purposes of calculating earnings per share ("EPS"), Athlon allocates net income (loss) to its shareholders and participating securities each quarter under the provisions of the "Earnings Per Share" topic of the ASC. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in distributions with common shares. For purposes of calculating EPS, unvested restricted stock units are considered participating securities. Net income (loss) per common share is calculated by dividing the shareholders' interest in net income (loss), after deducting the interests of participating securities, by the weighted average common shares outstanding.

New Accounting Pronouncements

        In December 2011, the FASB 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 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 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 consolidated financial statements.

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Note 3. Acquisitions

Element

        On October 3, 2011, Athlon 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's credit agreement and capital contributions from Holdings' partners. The operations of these properties have been included with those of Athlon from the date of acquisition. Athlon incurred approximately $6.4 million of transaction costs related to this acquisition, which are included in "Acquisition costs" in the accompanying Consolidated Statements of Operations. Of this amount, approximately $4.3 million was paid to Apollo. Please read "Note 12. 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):

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

        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.

	Year ended December 31, 2011
	(in thousands, except per share amounts)
Pro forma total revenues	$	89,618
Pro forma net income attributable to stockholders	$	9,777
Pro forma net income per common share:
Basic	$	0.15
Diluted	$	0.14

SandRidge

        On January 6, 2011, Athlon 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's credit

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3. Acquisitions (Continued)

agreement and capital contributions from Holdings' partners. The operations of these properties have been included with those of Athlon from the date of acquisition. Athlon incurred $2.6 million of transaction costs related to this acquisition, which are included in "Acquisition costs" in the accompanying Consolidated Statements of Operations. Of this amount, approximately $2.3 million was paid to Apollo. Please read "Note 12. 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):

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

Note 4. Fair Value Measurements

        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 December 31, 2013, the fair value of the senior notes was approximately $522.8 million using open market quotes ("Level 1" input).

Commodity Derivative Contracts

        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, which provide a fixed price for a notional amount of sales volumes. The following table summarizes Athlon's open commodity derivative contracts as of December 31, 2013:

Period	Average Daily Swap Volume		Weighted- Average Swap Price		Asset (Liability) Fair Market Value
	(Bbl)		(per Bbl)		(in thousands)
2014		7,950	$	92.67	$	(8,354	)
2015		1,300		93.18		2,330
					$	(6,024	)

        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 the third quarter of 2011, Athlon entered into additional oil puts that included deferred premiums. These deferred premiums increased Athlon's interest expense by approximately $0.2 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4. Fair Value Measurements (Continued)

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, 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:

Counterparty	Fair Market Value of Oil Derivative Contracts Committed
	(in thousands)
BNP Paribas	$	1,082

        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.

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Note 4. Fair Value Measurements (Continued)

Tabular Disclosures of Fair Value Measurements

        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 December 31, 2013
Assets
Derivatives—current	$	143		$	(143	)	$	—
Derivatives—noncurrent		2,330			—			2,330
Total assets		2,473			(143	)		2,330
Liabilities
Derivatives—current		(8,497	)		143			(8,354	)
Derivatives—noncurrent		—			—			—
Total liabilities		(8,497	)		143			(8,354	)
Net liabilities	$	(6,024	)	$	—		$	(6,024	)
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

(a)

Represents counterparty netting under master netting agreements, which allow for netting of commodity derivative contracts. These derivative instruments are reflected net on the accompanying Consolidated Balance Sheets.

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

		Amount of Loss (Gain) Recognized in Income
		Year ended December 31,
	Location of Loss (Gain) Recognized in Income
Derivatives Not Designated as Hedges		2013		2012			2011
		(in thousands)
Commodity derivative contracts	Derivative fair value loss (gain)	$	18,115	$	(9,293	)	$	7,959

101

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4. Fair Value Measurements (Continued)

Fair Value Hierarchy

        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:

•

Level 1—Inputs such as unadjusted, quoted prices that are available in active markets for identical assets or liabilities.

•

Level 2—Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable, such as quoted prices for similar assets and liabilities or quoted prices in inactive markets.

•

Level 3—Inputs that are unobservable for use when little or no market data exists requiring the use of valuation methodologies that result in management's best estimate of fair value.

        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:

•

Level 2—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. Settlement is determined by the average underlying price over a predetermined period of time. Athlon uses observable inputs in an option pricing valuation model to determine fair value such as: (i) current market and contractual prices for the underlying instruments; (ii) quoted forward prices for oil; (iii) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (iv) appropriate volatilities.

        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 $39,000 as of December 31, 2013 and an increase in the net commodity derivative asset of approximately $125,000 as of December 31, 2012.

102

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4. Fair Value Measurements (Continued)

        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	Net Asset (Liability)			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, 2013
Oil derivative contracts—swaps	$	(6,024	)	$	—	$	(6,024	)	$	—
As of December 31, 2012
Oil derivative contracts—swaps	$	4,069		$	—	$	4,069		$	—
Oil derivative contracts—collars		(80	)		—		(80	)		—
Total	$	3,989		$	—	$	3,989		$	—

Note 5. 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 Athlon's asset retirement obligations for the periods indicated:

	Year Ended December 31,
	2013			2012
	(in thousands)
Balance at January 1	$	5,049		$	3,704
Liabilities assumed in acquisitions		395			60
Liabilities incurred from new wells		1,013			815
Liabilities settled		(283	)		—
Accretion of discount		675			478
Revisions of previous estimates		6			(8	)
Balance at December 31		6,855			5,049
Less: current portion		60			—
Asset retirement obligations—long-term	$	6,795		$	5,049

Note 6. Long-Term Debt

Senior Notes

        In April 2013, Athlon 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 Athlon's credit agreement, to repay in full and terminate Athlon's former second lien

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6. Long-Term Debt (Continued)

term loan, to make a $75 million distribution to Holdings' Class A limited partners, and for general corporate 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 Athlon's ability to:

•

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

•

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

•

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

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

        Under the indenture, starting on April 15, 2016, Athlon 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, Athlon 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 Athlon's option, prior to April 15, 2016, Athlon 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, Athlon 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 Athlon 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, up 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, Athlon's former second lien term loan was paid off and retired and the borrowing base of Athlon's 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 2013.

Credit Agreement

        Athlon is a party to an amended and restated credit agreement dated March 19, 2013 (the "Credit Agreement"), which matures on March 19, 2018. The 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 Credit Agreement is $1.0 billion. Availability under the Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations.

104

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6. Long-Term Debt (Continued)

        In conjunction with the offering of the Notes in April 2013 as discussed above, the borrowing base under the Credit Agreement was reduced to $267.5 million. In May 2013, Athlon amended the Credit Agreement to, among other things, increase the borrowing base to $320 million. In November 2013, Athlon amended the Credit Agreement to, among other things, increase the borrowing base to $525 million. As of December 31, 2013, the borrowing base was $525 million and there were no outstanding borrowings and no outstanding letters of credit under the Credit Agreement.

        Obligations under the 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 Credit Agreement are guaranteed by Athlon's operating subsidiaries.

        Loans under the 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 Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table. Athlon also incurs a quarterly commitment fee on the unused portion of the Credit Agreement indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	Unused Commitment Fee			Applicable Margin for Eurodollar Loans			Applicable Margin for Base Rate Loans
Less than or equal to .30 to 1		0.375	%		1.50	%		0.50	%
Greater than .30 to 1 but less than or equal to .60 to 1		0.375	%		1.75	%		0.75	%
Greater than .60 to 1 but less than or equal to .80 to 1		0.50	%		2.00	%		1.00	%
Greater than .80 to 1 but less than or equal to .90 to 1		0.50	%		2.25	%		1.25	%
Greater than .90 to 1		0.50	%		2.50	%		1.50	%

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

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

•

a prohibition against incurring debt, subject to permitted exceptions;

•

a restriction on creating liens on Athlon's assets and the assets of its operating subsidiaries, subject to permitted exceptions;

•

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

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6. Long-Term Debt (Continued)

•

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

•

a requirement that Athlon maintain a ratio of consolidated total debt to EBITDAX (as defined in the Credit Agreement) of not more than 4.75 to 1.0 (which ratio changes to 4.5 to 1.0 beginning with the quarter ending June 30, 2014); and

•

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

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

Long-Term Debt Maturities

        The following table shows Athlon's long-term debt maturities as of December 31, 2013:

	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Credit Agreement	$	—	$	—	$	—	$	—	$	—	$	—	$	—
73/8% Senior Notes		500,000		—		—		—		—		—		500,000
Total	$	500,000	$	—	$	—	$	—	$	—	$	—	$	500,000

        During 2013, 2012, and 2011, the weighted-average interest rate for total indebtedness was 7.6%, 4.3%, and 3.8%, respectively.

Note 7. Stockholders' Equity

        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. These securities were offered and sold by Athlon in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act of 1933. On April 26, 2013, in connection with the corporate reorganization, 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. These securities were offered and sold by Athlon in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act of 1933. 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

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7. Stockholders' Equity (Continued)

received net proceeds of approximately $295.7 million, after deducting underwriting discounts and commissions and offering expenses. Athlon used the net proceeds from the IPO (i) to reduce outstanding borrowings under the Credit Agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes. 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%.

Preferred Stock

        Athlon's authorized capital stock includes 50,000,000 shares of preferred stock, none of which were issued and outstanding at December 31, 2013. Athlon does not plan to issue any shares of preferred stock.

Note 8. Taxes

Income Taxes

        As a result of the corporate reorganization on April 26, 2013, Athlon (a C-corporation) obtained most of the interests in Holdings. Prior to April 26, 2013, Holdings, Athlon's accounting predecessor, was a limited partnership not subject to federal income taxes.

        The components of income tax provision were as follows for the periods indicated:

	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Federal:
Current	$	1,135	$	—	$	—
Deferred		17,022		—		—
Total federal		18,157		—		—
State, net of federal benefit:
Deferred		993		1,928		470
Total state		993		1,928		470
Income tax provision	$	19,150	$	1,928	$	470

107

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 8. Taxes (Continued)

        The following table reconciles income tax provision with income tax at the Federal statutory rate for the periods indicated:

	Year Ended December 31,
	2013			2012		2011
	(in thousands)
Income (loss) before income taxes	$	79,572		$	54,942	$	(659	)
Less: net income prior to corporate reorganization		(27,320	)		—		—
Less: net income attributable to noncontrolling interest		(1,359	)		—		—
Income (loss) before income taxes and noncontrolling interest subsequent to corporate reorganization	$	50,893		$	54,942	$	(659	)
Income taxes at the Federal statutory rate	$	17,813		$	—	$	—
State income taxes, net of federal benefit		933			549		21
Provision to return adjustment		59			—		—
Permanent and other		345			1,379		449
Income tax provision	$	19,150		$	1,928	$	470

108

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 8. Taxes (Continued)

        The major components of net current deferred taxes and net long-term deferred taxes were as follows as of the dates indicated:

	December 31,
	2013			2012
	(in thousands)
Current:
Assets:
Derivative fair value loss	$	480		$	—
Total current deferred tax assets		480			—
Liabilities:
Prepaid insurance		(100	)		(8	)
Derivative fair value gain		—			(50	)
Total current deferred tax liabilities		(100	)		(58	)
Net current deferred tax asset (liability)	$	380		$	(58	)
Long-term:
Assets:
Alternative minimum tax credits	$	1,135		$	—
Derivative fair value loss		2,080			60
Net operating loss carryforward		43,164			—
Asset retirement obligations		519			8
Deferred equity-based compensation		1,406			—
Acquisition costs capitalized		3,351			95
Other		1,840			25
Total long-term deferred tax assets		53,495			188
Liabilities:
Book basis of oil and natural gas properties in excess of tax basis		(145,892	)		(2,528	)
Total long-term deferred tax liabilities		(145,892	)		(2,528	)
Net long-term deferred tax liability	$	(92,397	)	$	(2,340	)

        At December 31, 2013, Athlon had federal net operating loss ("NOL") carryforwards, which are available to offset future federal state taxable income, if any. At December 31, 2013, Athlon also had federal alternative minimum tax ("AMT") credits, which are available to reduce future federal regular tax liabilities in excess of AMT. Athlon believes it is more likely than not that the NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 8. Taxes (Continued)

Therefore, a valuation allowance against these deferred tax assets is not considered necessary. If unused, these carryforwards and credits will expire as follows:

Expiration Date	Federal AMT Credits		Federal NOL
	(in thousands)
2031	$	—	$	2,433
2032		—		77,749
2033		—		43,143
Indefinite		1,135		—
	$	1,135	$	123,325

        During 2013, 2012, and 2011, Athlon did not have any interest assessed by the taxing authorities or incur any penalties related to income taxes.

Note 9. Earnings Per Share

        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 is akin to a stock split and has been treated as such in Athlon's 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.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9. Earnings Per Share (Continued)

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

	Year ended December 31,
	2013			2012		2011
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	59,063		$	53,014	$	(1,129	)
Participation rights of unvested RSUs in undistributed earnings		(628	)		—		—
Basic undistributed net income (loss) attributable to stockholders	$	58,435		$	53,014	$	(1,129	)
Denominator:
Basic weighted average shares outstanding		72,915			66,340		66,340
Basic EPS attributable to stockholders	$	0.80		$	0.80	$	(0.02	)
Diluted EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	59,063		$	53,014	$	(1,129	)
Participation rights of unvested RSUs in undistributed earnings		(613	)		—		—
Effect of conversion of New Holdings Units to shares of Athlon's common stock		1,359			—		—
Diluted undistributed net income (loss) attributable to stockholders	$	59,809		$	53,014	$	(1,129	)
Denominator:
Basic weighted average shares outstanding		72,915			66,340		66,340
Effect of conversion of New Holdings Units to shares of Athlon's common stock(a)		1,856			1,856		—
Diluted weighted average shares outstanding		74,771			68,196		66,340
Diluted EPS attributable to stockholders	$	0.80		$	0.78	$	(0.02	)

(a)

For 2011, 1,855,563 New Holdings Units were outstanding but excluded from the EPS calculations because their effect would have been antidilutive.

Note 10. Employment Benefit Plans

401(k) Plan

        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 $585,000, $454,000, and $219,000 during 2013, 2012, and 2011, respectively. Athlon's 401(k) plan does not allow employees to invest in securities of Athlon.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10. Employment Benefit Plans (Continued)

Incentive Award Plan

        In August 2013, Athlon adopted the Athlon Energy Inc. 2013 Incentive Award Plan (the "Plan"). 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. 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 the 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.

        The aggregate number of shares of common stock available for issuance pursuant to awards granted under the Plan is 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:

•

shares subject to awards or portions of awards granted under the Plan which are forfeited, expire, or lapse for any reason, or are settled for cash without the delivery of shares, to the extent of such forfeiture, expiration, lapse, or cash settlement; and

•

shares that Athlon repurchases prior to vesting so that such shares are returned to Athlon.

        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 December 31, 2013, there were 7,761,087 shares available for issuance under the Plan. During 2013, Athlon recorded non-cash stock-based compensation expense related to the Plan of $4.0 million, 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 2013, Athlon also capitalized $263,000 of non-cash stock-based compensation expense related to the Plan as a component of "Evaluated, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10. Employment Benefit Plans (Continued)

        RSUs vest over three years, subject to the relative performance of Athlon's stock to that of a designated peer group for Athlon's management team. The following table summarizes the changes in Athlon's unvested RSUs for 2013 (presented at the target level):

	Number of Shares		Weighted-Average Grant Date Fair Value Per Share
Outstanding at January 1		—	$	—
Granted		638,913		34.88
Vested		—		—
Forfeited		—		—
Outstanding at December 31		638,913		34.88

        During 2013, Athlon issued 411,413 RSUs to employees and non-employee directors, the vesting of which is dependent only on the passage of time and continued employment. The following table provides information regarding Athlon's outstanding RSUs at December 31, 2013 the vesting of which is dependent only on the passage of time and continued employment:

	Year of Vesting
Year of Grant	2014		2015		2016		Total
2013		137,138		137,138		137,137		411,413

        During 2013, Athlon also issued 227,500 RSUs to Athlon's management team, the vesting of which is dependent not only on the passage of time and continued employment, but also on the relative performance of Athlon's stock to that of a designated peer group. One-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the number of shares will be earned if the higher maximum target levels are met. If performance is below the designated minimum levels for all performance targets, no performance-based shares will be earned. Performance-based awards were valued using a Monte Carlo simulation. The following table provides information regarding Athlon's outstanding RSUs at December 31, 2013 (presented at the target level) the vesting of which is dependent not only on the passage of time and continued employment, but also on the relative performance of Athlon's stock to that of a designated peer group:

	Year of Vesting
Year of Grant	2014		2015		2016		Total
2013		75,834		75,833		75,833		227,500

        None of Athlon's unvested RSUs are subject to variable accounting. As of December 31, 2013, Athlon had approximately $16.6 million of total unrecognized compensation cost related to unvested RSUs, which is expected to be recognized over a weighted-average period of approximately 2.6 years.

Class B Interests

        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

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10. Employment Benefit Plans (Continued)

connection with the 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, 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 2013, 2012, and 2011, Athlon recorded approximately $1.3 million, $152,000, and $106,000, 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 2013 and 2012, Athlon capitalized approximately $415,000 and $93,000, respectively, of non-cash stock-based compensation expense as a component of "Evaluated, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

Note 11. Commitments and Contingencies

Leases

        Athlon leases certain office space that has non-cancelable lease terms in excess of one year. The following table summarizes the remaining non-cancelable future payments under these operating leases as of December 31, 2013:

	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Corporate office lease	$	1,031	$	375	$	375	$	281	$	—	$	—	$	—
Midland office lease		285		92		96		97		—		—		—
Total	$	1,316	$	467	$	471	$	378	$	—	$	—	$	—

        Athlon's operating lease rental expense was approximately $490,000, $507,000, and $272,000 during 2013, 2012, and 2011, respectively.

Litigation

        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.

Note 12. Related Party Transactions

Transaction Fee Agreement

        Athlon was a party to a Transaction Fee Agreement, dated August 23, 2010, which required it 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 an affiliate, Apollo Global Securities, LLC. Upon the consummation of Athlon's IPO, the Transaction Fee Agreement was

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 12. Related Party Transactions (Continued)

terminated. Since Athlon's 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.

Services Agreement

        Athlon was a party to a Services Agreement, dated August 23, 2010, which required it 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 2013, 2012, and 2011, Athlon incurred approximately $500,000, $493,000, and $411,000, respectively, of Advisory Fees, which are included in "General and administrative expenses" in the accompanying Consolidated Statements of Operations.

        Upon the consummation of Athlon's IPO, the Services Agreement was terminated and Athlon paid a termination fee of $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, Athlon also agreed to indemnify Apollo and its affiliates and their respective limited partners, general partners, directors, members, officers, managers, employees, agents, advisors, 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.

Distribution

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

Exchange Agreement

        Upon the consummation of its IPO, Athlon entered into an exchange agreement with its management team and certain employees who hold New Holdings Units. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 12. Related Party Transactions (Continued)

Tax Receivable Agreement

        Upon the consummation of its IPO, Athlon entered into a tax receivable agreement with its management team and certain employees who hold New Holdings Units 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.

Note 13. Subsequent Events

        Subsequent to December 31, 2013, Athlon entered into additional oil swaps. The following table summarizes Athlon's open commodity derivative contracts as of March 7, 2014:

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
2014		9,369		92.61
Q1 2015		4,300		91.29
Q2 2015		4,300		91.29
Q3 2015		1,300		93.18
Q4 2015		1,300		93.18
2015		2,788		91.74

        On February 6, 2014, Athlon completed the acquisition of certain oil and natural gas properties and related assets in the Midland Basin of West Texas for approximately $88 million in cash (subject to customary post-closing adjustments), pursuant to a Purchase and Sale Agreement dated January 10, 2014 with an effective date of September 1, 2013. Athlon also agreed to acquire additional working interests in the properties, partially offset by the exercise of certain preferential rights, with the net effect of an $8.7 million purchase price increase. The acquisition was financed through cash on hand and borrowings under the Credit Agreement.

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SUPPLEMENTARY INFORMATION

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:

	December 31,
	2013			2012
	(in thousands)
Oil and natural gas properties and equipment, at cost—full cost method:
Evaluated, including wells and related equipment	$	1,244,178		$	788,571
Unevaluated		89,859			89,860
Accumulated depletion, depreciation, and amortization		(160,779	)		(73,824	)
	$	1,173,258		$	804,607

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

	Year ended December 31,
	2013		2012		2011
	(in thousands)
Acquisitions:
Proved properties(a)	$	19,609	$	42,122	$	287,400
Unproved properties(b)		34,922		38,908		130,273
Total acquisitions		54,531		81,030		417,673
Development(c)		180,011		201,174		71,403
Exploration(d)		218,680		75,008		17,829
Total costs incurred	$	453,222	$	357,212	$	506,905

(a)

Includes asset retirement obligations incurred of approximately $395,000, $60,000, and $3.3 million during 2013, 2012, and 2011, respectively.

(b)

Costs incurred for unproved properties are excluded from the amortization base.

(c)

Includes asset retirement obligations incurred of approximately $609,000, $606,000, and $108,000 during 2013, 2012, and 2011, respectively.

(d)

Includes asset retirement obligations incurred of approximately $404,000, $209,000, and $58,000 during 2013, 2012, and 2011, respectively.

Oil & Natural Gas Producing Activities—Unaudited

        All of Athlon's results of operations relate to oil and natural gas producing activities. Athlon's only cost center is the Permian Basin in West Texas. Athlon's average depletion rate per BOE of production was $19.51, $21.03, and $20.32 for 2013, 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.

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SUPPLEMENTARY INFORMATION (Continued)

        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:

	December 31,
	2013		2012		2011
Oil (per Bbl)	$	96.78	$	94.71	$	93.25
Natural gas (per Mcf)		3.67		2.75		3.53

        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. Income tax expense is calculated by applying the statutory income tax rates to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis.

        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.

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SUPPLEMENTARY INFORMATION (Continued)

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

	December 31,
	2013		2012		2011
Proved developed reserves:
Oil (MBbls)		26,436		14,470		7,942
Natural gas (MMcf)		55,358		31,965		14,063
Natural gas liquids (MBbls)		11,077		5,900		3,211
Combined (MBOE)		46,740		25,698		13,496
Proved undeveloped reserves:
Oil (MBbls)		44,738		34,953		18,030
Natural gas (MMcf)		96,848		71,718		37,497
Natural gas liquids (MBbls)		19,645		13,375		8,338
Combined (MBOE)		80,524		60,281		32,618
Proved reserves:
Oil (MBbls)		71,174		49,423		25,972
Natural gas (MMcf)		152,206		103,683		51,560
Natural gas liquids (MBbls)		30,722		19,275		11,549
Combined (MBOE)		127,264		85,979		46,114

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

	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Oil Equivalent (MBOE)
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		(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
Purchases of minerals-in-place		495			877			197			838
Extensions and discoveries		23,895			45,424			9,566			41,031
Revisions of previous estimates(a)		43			7,149			2,638			3,874
Production		(2,682	)		(4,927	)		(954	)		(4,458	)
Balance, December 31, 2013		71,174			152,206			30,722			127,264

(a)

Revisions to previous estimates are comprised of 6,512 MBOE of negative revisions for proved undeveloped locations that are not currently scheduled to be drilled within the next five years and 10,386 MBOE of positive net revisions due to the combination of price, cost, and technical revisions.

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SUPPLEMENTARY INFORMATION (Continued)

        The following is a standardized measure of discounted future net cash flows and changes applicable to proved reserves. The future net 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 any 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 flows 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 future net cash flows was as follows as of the dates indicated:

	December 31,
	2013			2012			2011
	(in thousands)
Future cash inflows	$	8,053,437		$	5,361,058		$	3,155,756
Future production costs		(2,421,186	)		(1,811,514	)		(972,343	)
Future development costs		(1,242,817	)		(1,060,785	)		(569,672	)
Future income taxes		(1,347,259	)		(37,527	)		(22,090	)
Future net cash flows		3,042,175			2,451,232			1,591,651
10% annual discount		(1,942,501	)		(1,600,318	)		(1,010,494	)
Standardized measure of discounted estimated future net cash flows	$	1,099,674		$	850,914		$	581,157

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SUPPLEMENTARY INFORMATION (Continued)

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

	Year ended December 31,
	2013			2012			2011
	(in thousands)
Net change in prices and production costs	$	250,716		$	(109,214	)	$	73,093
Purchases of minerals-in-place		11,601			81,304			394,248
Extensions, discoveries, and improved recovery		448,208			376,493			101,396
Revisions of previous quantity estimates		50,202			(189,505	)		27,499
Production, net of production costs		(246,327	)		(121,170	)		(47,626	)
Previously estimated development costs incurred during the period		130,900			119,361			43,994
Accretion of discount		86,658			59,144			20,072
Change in estimated future development costs		(17,389	)		60,210			(22,239	)
Net change in income taxes		(520,162	)		(5,378	)		(2,809	)
Change in timing and other		54,353			(1,488	)		(6,471	)
Net change in standardized measure		248,760			269,757			581,157
Standardized measure, beginning of year		850,914			581,157			—
Standardized measure, end of year	$	1,099,674		$	850,914		$	581,157

Selected Quarterly Financial Data—Unaudited

        The following table provides selected quarterly financial data for the periods indicated:

	Quarter
	First			Second		Third			Fourth
	(in thousands, except per share data)
2013
Revenues	$	54,746		$	65,165	$	88,425		$	91,037
Operating income	$	15,380		$	41,454	$	14,210		$	45,162
Net income attributable to stockholders	$	10,879		$	23,697	$	2,482		$	22,005
Net income per common share:
Basic	$	0.16		$	0.36	$	0.03		$	0.27
Diluted	$	0.16		$	0.36	$	0.03		$	0.27
2012
Revenues	$	33,232		$	35,791	$	42,086		$	46,002
Operating income (loss)	$	(8,869	)	$	58,295	$	430		$	15,035
Net income (loss) attributable to stockholders	$	(10,000	)	$	54,604	$	(2,096	)	$	10,506
Net income (loss) per common share:
Basic	$	(0.15	)	$	0.82	$	(0.03	)	$	0.16
Diluted	$	(0.15	)	$	0.80	$	(0.03	)	$	0.15

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

        In accordance with 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 December 31, 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 be required to make our first assessment of internal control over financial reporting under Section 404 for our 2014 Annual Reporton Form 10-K.

Changes in Internal Control over Financial Reporting

        There were no changes in our internal control over financial reporting during the fourth quarter of 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

Disclosure Pursuant to Section 219 of the Iran Threat Reduction and Syria Human Rights Act

        Apollo Global Management, LLC ("Apollo") has provided notice to us that, as of October 24, 2013, certain investment funds managed by affiliates of Apollo beneficially owned approximately 22% of the limited liability company interests of CEVA Holdings, LLC ("CEVA"). Under the limited liability company agreement governing CEVA, certain investment funds managed by affiliates of Apollo hold a majority of the voting power of CEVA and have the right to elect a majority of the board of CEVA. CEVA may be deemed to be under common control with us, but this statement is not meant to be an admission that common control exists. As a result, it appears that we are required to provide disclosures as set forth below pursuant to Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 ("ITRA") and Section 13(r) of the Securities Exchange Act of 1934, as amended (the "Exchange Act").

        Apollo has informed us that CEVA has provided it with the information below relevant to Section 13(r) of the Exchange Act. The disclosure below does not relate to any activities conducted by us and does not involve us or our management. The disclosure relates solely to activities conducted by

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CEVA and its consolidated subsidiaries. We have not independently verified or participated in the preparation of the disclosure below.

        "Through an internal review of its global operations, CEVA has identified the following transactions in an Initial Notice of Voluntary Self-Disclosure that CEVA filed with the U.S. Treasury Department Office of Foreign Assets Control ("OFAC") on October 28, 2013. CEVA's review is ongoing. CEVA will file a further report with OFAC after completing its review.

        The internal review indicates that, in February 2013, CEVA Freight Holdings (Malaysia) SDN BHD ("CEVA Malaysia") provided customs brokerage for export and local haulage services for a shipment of polyethylene resin to Iran shipped on a vessel owned and/or operated by HDS Lines, also an SDN. The revenues and net profits for these services were approximately $779.54 USD and $311.13 USD, respectively. In September 2013, CEVA Malaysia provided customs brokerage services for the import into Malaysia of fruit juice from Alifard Co. in Iran via HDS Lines. The revenues and net profits for these services were approximately $227.41 USD and $89.29 USD, respectively.

        These transactions violate the terms of internal CEVA compliance policies, which prohibit transactions involving Iran. Upon discovering these transactions, CEVA promptly launched an internal investigation, and is taking action to block and prevent such transactions in the future. CEVA intends to cooperate with OFAC in its review of this matter."

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        The information required in response to this item will be set forth in our definitive proxy statement for the 2014 annual meeting of stockholders and is incorporated herein by reference.

        We have adopted a Code of Business Conduct and Ethics covering our directors, officers, and employees, which is available free of charge on our website (www.athlonenergy.com). We will post on our website any amendments to the Code of Business Conduct and Ethics or waivers of the Code of Business Conduct and Ethics for directors and executive officers.

ITEM 11.    EXECUTIVE COMPENSATION

        The information required in response to this item will be set forth in our definitive proxy statement for the 2014 annual meeting of stockholders and is incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

        The following table sets forth information about our common stock that may be issued under equity compensation plans as of December 31, 2013:

	(a)		(b)		(c)
	Number of Securities to Be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
Equity compensation plans approved by security holders(a)		—	$	—		7,761,087
Equity compensation plans not approved by security holders		—	$	—		—
Total		—	$	—		7,761,087

(a)

There are no outstanding options, warrants, or equity rights awarded under our equity compensation plans. Excludes 638,913 shares of unvested restricted stock units. Please read Note 10 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of our equity compensation plans.

        Additional information required in response to this item will be set forth in our definitive proxy statement for the 2014 annual meeting of stockholders and is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The information required in response to this item will be set forth in our definitive proxy statement for the 2014 annual meeting of stockholders and is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

        The information required in response to this item will be set forth in our definitive proxy statement for the 2014 annual meeting of stockholders and is incorporated herein by reference.

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PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as a part of this Report:

1.

Financial Statements:

	Page
Report of Independent Registered Public Accounting Firm		85
Consolidated Balance Sheets as of December 31, 2013 and 2012		86
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012, and 2011		87
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2013, 2012, and 2011		88
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012, and 2011		89
Notes to Consolidated Financial Statements		90

2.

Financial Statement Schedules:

        All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements and related notes.

(b)

Exhibits

Exhibit No.		Description
	3.1	Amended and Restated Certificate of Incorporation of Athlon Energy Inc. (incorporated by reference to Exhibit 3.1 of Athlon's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, filed with the SEC on August 14, 2013).
	3.2	Amended and Restated Bylaws of Athlon Energy Inc. (incorporated by reference to Exhibit 3.2 of Athlon's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, filed with the SEC on August 14, 2013).
	4.1	Indenture between Wells Fargo Bank, N.A. and Athlon Holdings LP dated April 17, 2013 relating to the 73/8% Senior Notes due 2021 (including form of Note) (incorporated by reference to Exhibit 4.2 to Athlon's Registration Statement on Form S-1, filed with the SEC on June 5, 2013).
	4.2	Registration Rights Agreement among Athlon Holdings LP, Athlon Finance Corp. and Merrill Lynch, Pierce, Fenner & Smith Incorporated dated April 17, 2013 relating to the 73/8% Senior Notes due 2021 (incorporated by reference to Exhibit 4.3 to Athlon's Registration Statement on Form S-1, filed with the SEC on June 5, 2013).
	4.3	Supplemental Indenture, dated August 14, 2013, among Athlon Energy Inc., Athlon Holdings LP, Athlon Finance Corp. and Wells Fargo Bank, National Association, as Trustee, with respect to the indenture, dated as of April 17, 2013, relating to Athlon Holdings LP and Athlon Finance Corp.'s 73/8% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Athlon's Current Report on Form 8-K, filed with the SEC on August 20, 2013).

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Exhibit No.			Description
	10.1		Amended and Restated Credit Agreement, dated as of March 19, 2013, among Athlon Holdings LP, Bank of America, N.A., as Administrative Agent and L/C Issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Athlon's Registration Statement on Form S-1, filed with the SEC on June 5, 2013).
	10.2		Borrowing Base Redetermination and First Amendment to Amended and Restated Guarantee Agreement, dated as of May 31, 2013 by and among Athlon Holdings LP, Bank of America, N.A., as Administrative Agent and L/C Issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Athlon's Registration Statement on Form S-1, filed with the SEC on June 5, 2013).
	10.3	*	First Amendment to Amended and Restated Credit Agreement and Borrowing Base Redetermination, dated as of November 13, 2013 by and among Athlon Holdings LP, Bank of America, N.A., as Administrative Agent and L/C Issuer, and the lenders party thereto.
	10.4	+	Form of Director and Officer Indemnification Agreement between Athlon Energy Inc. and each of the officers and directors thereof (incorporated by reference to Exhibit 10.12 to Amendment No. 1 to Athlon's Registration Statement on Form S-1, filed with the SEC on June 27, 2013).
	10.5		Tax Receivable Agreement by and among Athlon Energy Inc., Athlon Holdings LP, and each of the Partners named therein (incorporated by reference to Exhibit 10.7 to Athlon's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
	10.6		Exchange Agreement by and among Athlon Energy Inc. and each of the Partners named therein (incorporated by reference to Exhibit 10.8 to Athlon's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
	10.7		Stockholders Agreement by and among Athlon Energy Inc. and those stockholders named therein (incorporated by reference to Exhibit 10.9 to Athlon's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
	10.8	+	Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and Robert C. Reeves (incorporated by reference to Exhibit 10.1 to Athlon's Current Report on Form 8-K, filed with the SEC on August 15, 2013).
	10.9	+	Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and William B. D. Butler (incorporated by reference to Exhibit 10.2 to Athlon's Current Report on Form 8-K, filed with the SEC on August 15, 2013).
	10.10	+	Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and Nelson K. Treadway (incorporated by reference to Exhibit 10.3 to Athlon's Current Report on Form 8-K, filed with the SEC on August 15, 2013).
	10.11	+	Athlon Energy Inc. 2013 Incentive Stock Plan (incorporated by reference to Exhibit 4.3 to Athlon's Registration Statement on Form S-8 (File No. 333-190734), filed with the SEC on August 20, 2013).

126

ATHLON ENERGY INC.

Exhibit No.			Description
	10.12		Advisory Services and Transaction Fee Termination Agreement by and among Athlon Holdings LP, Apollo Management VII, L.P. and Apollo Global Securities, LLC (incorporated by reference to Exhibit 10.10 to Athlon's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
	10.13		Amended and Restated Agreement of Limited Partnership of Athlon Holdings LP (incorporated by reference to Exhibit 10.11 to Athlon's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
	10.14	+	Form of Restricted Stock Unit Grant Notice—Executive (incorporated by reference to Exhibit 10.6 to Athlon's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
	21.1	*	Subsidiaries of Athlon Energy Inc.
	23.1	*	Consent of Ernst & Young LLP.
	23.2	*	Consent of Cawley, Gillespie & Associates, Inc.
	31.1	*	Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).
	31.2	*	Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).
	32.1	*	Section 1350 Certification (Principal Executive Officer).
	32.2	*	Section 1350 Certification (Principal Financial Officer).
	99.1	*	Report of Cawley, Gillespie & Associates, Inc.'s for Athlon Energy Inc.'s proved reserves at December 31, 2013 dated as of February 7, 2014.
	101.INS	*	XBRL Instance Document.
	101.SCH	*	XBRL Taxonomy Extension Schema Document.
	101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase.
	101.DEF	*	XBRL Taxonomy Extension Definition Linkbase Document.
	101.LAB	*	XBRL Taxonomy Extension Labels Linkbase Document.
	101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document.

*

Filed herewith.

+

Management contract or compensatory plan, contract, or arrangement.

127

ATHLON ENERGY INC.

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	By:	Athlon Energy Inc.
Date: March 7, 2014	By:	/s/ ROBERT C. REEVES Robert C. Reeves President, Chief Executive Officer, and Director

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title or Capacity	Date
/s/ ROBERT C. REEVES Robert C. Reeves	President, Chief Executive Officer, and Director (Principal Executive Officer)	March 7, 2014
/s/ WILLIAM B. D. BUTLER William B. D. Butler	Vice President—Chief Financial Officer (Principal Financial Officer)	March 7, 2014
/s/ JOHN C. SOUDERS John C. Souders	Vice President—Controller (Principal Accounting Officer)	March 7, 2014
/s/ GREGORY A. BEARD Gregory A. Beard	Director	March 7, 2014
/s/ TED A. GARDNER Ted A. Gardner	Director	March 7, 2014
/s/ WILSON B. HANDLER Wilson B. Handler	Director	March 7, 2014
/s/ SAM OH Sam Oh	Director	March 7, 2014

128

ATHLON ENERGY INC.

Signature	Title or Capacity	Date
/s/ MARK A. STEVENS Mark A. Stevens	Director	March 7, 2014
/s/ RAKESH WILSON Rakesh Wilson	Director	March 7, 2014

129

EX-10.3

Exhibit 10.3

FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

AND

BORROWING BASE REDETERMINATION

THIS FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT AND BORROWING BASE REDETERMINATION (herein called this “Amendment”) is made as of November 14, 2013 by and among Athlon Holdings LP, a Delaware limited partnership (the “Borrower”), each Lender party hereto as set forth on the signature pages hereto, Bank of America, N.A., as the Administrative Agent, the Swingline Lender and the Issuing Bank, and each Guarantor party hereto.

W I T N E S S E T H:

WHEREAS, the Borrower, the Lenders, the Administrative Agent, the Swingline Lender and the Issuing Bank are party to that certain Amended and Restated Credit Agreement dated as of March 19, 2013 (as amended, supplemented or modified from time to time prior to the date hereof, the “Original Agreement”), whereby the Issuing Bank became obligated to issue Letters of Credit for the account of the Credit Parties and the Lenders became obligated to make loans to the Borrower as therein provided; and

WHEREAS, The Borrower, the Administrative Agent and the Lenders desire to set forth the Redetermination of the Borrowing Base, and the Borrower, the Administrative Agent, the Issuing Bank and the Lenders desire to amend the Original Agreement to set forth a revised schedule of each Lender’s Commitment Percentage thereunder;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans and other credit which may hereafter be made by the Lenders and the Issuing Bank to the Credit Parties, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

DEFINITIONS AND REFERENCES

Section 1.1.Defined Terms.  Unless the context otherwise requires, capitalized terms used in this Amendment shall have the meanings assigned to them either in the preamble and recitals hereto or in the Original Agreement, as applicable.

[FIRST AMENDMENT TO CREDIT AGREEMENT]

ARTICLE II.

AMENDMENT TO ORIGINAL AGREEMENT AND BORROWING BASE REDETERMINATION

Section 2.1.Amendment to Schedule 1.01(a).  Schedule 1.01(a) of the Original Agreement is hereby amended in its entirety and replaced with Schedule 1.01(a)  attached hereto.

Section 2.2.Borrowing Base.  Pursuant to Section 2.14 of the Original Agreement, the Lenders and the Administrative Agent have redetermined the Borrowing Base to be $525,000,000, which Borrowing Base shall be effective on the Effective Date set forth below and shall remain in effect until the next Redetermination or adjustment of the Borrowing Base pursuant to the Original Agreement.  The Borrower hereby accepts such Borrowing Base as so redetermined, and the Lenders party hereto, the Administrative Agent and the Borrower hereby acknowledge that this is the Scheduled Redetermination to be made as of October 1, 2013 or as promptly as possible thereafter.

ARTICLE III.

CONDITIONS OF EFFECTIVENESS

Section 3.1.Conditions to Effectiveness of Amendment.  This Amendment shall become effective (the “Effective Date”) when and only when:

(a)the Administrative Agent shall have received executed counterparts of this Amendment from the Borrower, each Guarantor and the Lenders;

(b)the Borrower shall have paid to the Administrative Agent, for the account of each Lender a fee in the amount equal to 0.375% times the positive remainder, if any, of (i) such Lender’s Commitment Percentage of the Borrowing Base after giving effect to the provisions of Sections 2.1 and 2.2 of this Amendment, minus (ii) such Lender’s Commitment Percentage of the Borrowing Base immediately prior to giving effect to the provisions of Sections 2.1 and 2.2 of this Amendment (or if a Lender was not party to the Original Agreement prior to the effectiveness of this Amendment, zero), which fee shall be due and payable on the date hereof; and

(c)each of the representations and warranties made by the Borrower and each Guarantor in or pursuant to the Credit Documents shall be true and correct in all material respects (or in all respects if such representation or warranty is by its terms already qualified as to materiality), as if made on and as of such date, except for any representations and warranties made as of a specified date, which were true and correct in all material respects as of such specified date.

2

ARTICLE IV.

MISCELLANEOUS

Section 4.1.Ratification of Agreements.  By its acceptance hereof, each of the Borrower and each Guarantor hereby ratifies and confirms each Credit Document to which it is a party in all respects, after giving effect to the Borrowing Base redetermination and amendments set forth herein.  Any reference to the Original Agreement in any Credit Document shall be deemed to be a reference to the Original Agreement as hereby amended.  The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein or therein, operate as a waiver of any right, power or remedy of the Administrative Agent or the Lenders under the Original Agreement, or any other Credit Document nor constitute a waiver of any provision of the Original Agreement, or any other Credit Document.

Section 4.2.New Lender Commitment.  By its execution and delivery of this Amendment, Goldman Sachs Bank USA (the “New Lender”) hereby assumes all of the rights and obligations of a Lender under the Original Agreement in respect of its Commitment set forth on Schedule 1.01(a) attached hereto.  The Commitments of the New Lender and the increase in the Borrowing Base set forth herein shall not represent an increase in the Total Commitments pursuant to Section 2.16 of the Original Agreement.  The Administrative Agent, the Swingline Lender, the Issuing Bank, and the Borrower hereby consent to and approve the New Lender and the Commitment of the New Lender.

Section 4.3.New Lender Representations and Agreements.  The New Lender hereby represents and warrants to the Administrative Agent, the Swingline Lender and the Issuing Bank as follows:  (a) it is not the Borrower, an Affiliate of the Borrower, a Subsidiary of the Borrower, a natural person, a Defaulting Lender, a Subsidiary of a Defaulting Lender, or a Person who, upon becoming a Lender, would constitute a Defaulting Lender or a Subsidiary of a Defaulting Lender, (c) from and after the Effective Date, it shall be bound by the provisions of the Original Agreement (as amended hereby) as a Lender thereunder and, to the extent of its Commitment, shall have the obligations of a Lender thereunder, (d) it is sophisticated with respect to decisions to acquire assets of the type represented by such Commitment and either it, or the Person exercising discretion in making its decision to acquire such Commitment, is experienced in acquiring assets of such type, (e) it has received a copy of the Original Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant thereto and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Amendment on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent, the Swingline Lender, the Issuing Bank, or any other Lender, and (f) if it is a Foreign Lender, attached hereto is any documentation required to be delivered by it pursuant to the terms of the Original Agreement, duly completed and executed by it; and agrees that (1) it will, independently and without reliance on the Administrative Agent, the Swingline Lender, Issuing Bank or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (2) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

3

Section 4.4.Reallocation .  The Lenders have authorized the Administrative Agent and the Borrower to make non-ratable borrowings and prepayments of the Loans, and if any such prepayment requires the payment of Eurodollar Rate Loans other than on the last day of the applicable Interest Period, the Borrower shall pay any required amounts pursuant to Section 2.11, in order to keep the outstanding Loans ratable with any revised Applicable Percentages arising from any nonratable increase in the Commitments under this Amendment and from the Commitments of the New Lender.

Section 4.5.Survival of Agreements.  All representations, warranties, covenants and agreements of any Credit Party herein shall survive the execution and delivery of this Amendment and the performance hereof, and shall further survive until all of the Obligations are paid in full.

Section 4.6.Credit Documents.  This Amendment is a Credit Document, and all provisions in the Original Agreement as amended hereby pertaining to Credit Documents apply hereto and thereto.

Section 4.7.Governing Law.  This Amendment shall be governed by and construed in accordance with the Laws of the State of New York.

Section 4.8.Counterparts; Fax.  This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment.  This Amendment may be validly executed by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER CREDIT DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES HERETO.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES HERETO.

[THE REMAINDER OF THIS PAGE HAS BEEN INTENTIONALLY LEFT BLANK.]

4

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

ATHLON HOLDINGS LP
By:		/s/ Robert C. Reeves
		Robert C. Reeves
		President and Chief Executive Officer
ATHLON ENERGY LLC
ATHLON ENERGY OPERATING LLC
ATHLON FE OPERATING LLC
ATHLON FINANCE CORP.
By:		/s/ Robert C. Reeves
		Robert C. Reeves
		Chief Executive Officer
ATHLON FE ENERGY LP
By:		Athlon Energy LLC, its general partner
	By:		/s/ Robert C. Reeves
			Robert C. Reeves
			Chief Executive Officer
ATHLON ENERGY LP
By:	Athlon Energy LLC, its general partner
	By:		/s/ Robert C. Reeves
			Robert C. Reeves
			Chief Executive Officer

[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT]

BANK OF AMERICA, N.A., as the
Administrative Agent
By:	/s/ Mollie S. Canup
Name:	Mollie S. Canup
Title:	Vice President
BANK OF AMERICA, N.A., as the Issuing Bank,
the Swingline Lender and a Lender
By:	/s/ Adam H. Fey
Name:	Adam H. Fey
Title:	Director
WELLS FARGO BANK, NATIONAL
ASSOCIATION, as a Lender
By:	/s/ Greg Smothers
Name:	Greg Smothers
Title:	Director
THE BANK OF NOVA SCOTIA, as a Lender
By:	/s/ Terry Donovan
Name:	Terry Donovan
Title:	Managing Director
ROYAL BANK OF CANADA, as a Lender
By:	/s/ Don J. McKinnerney
Name:	Don J. McKinnerney
Title:	Authorized Signatory

[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT]

CREDIT AGRICOLE CORPORATE AND
INVESTMENT BANK, as a Lender
By:	/s/ Dennis Petito
Name:	Dennis Petito
Title:	Managing Director
By:	/s/ Michael D. Willis
Name:	Michael D. Willis
Title:	Managing Director
UBS LOAN FINANCE LLC, as a Lender
By:	/s/ Lana Gifas
Name:	Lana Gifas
Title:	Director
By:	/s/ Jennifer Anderson
Name:	Jennifer Anderson
Title:	Associate Director
UNION BANK, N.A., as a Lender
By:	/s/ Alison White
Name:	Alison White
Title:	Vice President
CITIBANK, N.A., as a Lender
By:	/s/ John Miller
Name:	John Miller
Title:	Vice President
BARCLAYS BANK PLC, as a Lender
By:	/s/ Noam Azachi
Name:	Noam Azachi
Title:	Vice President

[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT]

CREDIT SUISSE AG, CAYMAN ISLANDS
BRANCH, as a Lender
By:	/s/ Kevin Buddhdew
Name:	Kevin Buddhdew
Title:	Authorized Signatory
By:	/s/ Michael Spaight
Name:	Michael Spaight
Title:	Authorized Signatory
GOLDMAN SACHS BANK USA, as a Lender
By:	/s/ Mark Walton
Name:	Mark Walton
Title:	Authorized Signatory

[SIGNATURE PAGE TO FIRST AMENDMENT TO CREDIT AGREEMENT]

EX-21.1

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Exhibit 21.1

Subsidiaries of Athlon Energy Inc.

Name of Subsidiary	State or other Jurisdiction of Incorporation or Organization
Athlon Holdings GP LLC		Delaware
Athlon Holdings LP		Delaware
Athlon Finance Corp.		Delaware

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Exhibit 21.1

Subsidiaries of Athlon Energy Inc.

EX-23.1

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-190734) pertaining to the Athlon Energy Inc. 2013 Incentive Award Plan of our report dated March 7, 2014, with respect to the consolidated financial statements of Athlon Energy Inc., included in this Annual Report (Form 10-K) for the year ended December 31, 2013.

/s/ Ernst & Young LLP

Fort Worth, Texas
March 7, 2014

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

EX-23.2

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Exhibit 23.2

CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE,	306 WEST SEVENTH STREET, SUITE 302 FORT	1000 LOUISIANA STREET,
SUITE 100	WORTH, TEXAS 76102-4987	SUITE 625
AUSTIN, TEXAS 78729-1707	817- 336-2461	HOUSTON, TEXAS 77002-
512-249-7000		5008
	www.cgaus.com	713-651-9944

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

        We hereby consent to the reference of our firm and to the use of the oil and gas reserve information based on the reserve report dated February 7, 2014 in the Athlon Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2013 to be filed with the U.S. Securities and Exchange Commission. We also consent to the inclusion of our report dated February 7, 2014 as an exhibit to the Form 10-K. We also consent to the incorporation by reference of this information into the Company's Registration Statements on Form S-8 (No. 333-190734).

Sincerely,

/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693

March 7, 2014
Fort Worth, Texas

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Exhibit 23.2

CAWLEY, GILLESPIE & ASSOCIATES, INC. PETROLEUM CONSULTANTS
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

EX-31.1

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Exhibit 31.1

Rule 13a-14(a)/15d-14(a) Certification

I, Robert C. Reeves, certify that:

1.

I have reviewed this annual report on Form 10-K of Athlon Energy Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 7, 2014

/s/ ROBERT C. REEVES
Robert C. Reeves
President and Chief Executive Officer

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Exhibit 31.1

Rule 13a-14(a)/15d-14(a) Certification

EX-31.2

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Exhibit 31.2

Rule 13a-14(a)/15d-14(a) Certification

I, William B. D. Butler, certify that:

1.

I have reviewed this annual report on Form 10-K of Athlon Energy Inc.;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 7, 2014

/s/ WILLIAM B. D. BUTLER
William B. D. Butler
Vice President—Chief Financial Officer

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Exhibit 31.2

Rule 13a-14(a)/15d-14(a) Certification

EX-32.1

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Exhibit 32.1

Section 1350 Certification

        In connection with the Annual Report of Athlon Energy Inc. ("Athlon") on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission (the "SEC") on the date hereof (the "Report"), I, Robert C. Reeves, Chief Executive Officer of Athlon, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

        (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Athlon.

Date: March 7, 2014

/s/ ROBERT C. REEVES
Robert C. Reeves
President and Chief Executive Officer

        A signed original of this written statement required by Section 906 has been provided to Athlon and will be retained by Athlon and furnished to the SEC or its staff upon request.

Note: The certification of the registrant furnished in this exhibit is not deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that Section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.

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Exhibit 32.1

Section 1350 Certification

EX-32.2

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Exhibit 32.2

Section 1350 Certification

        In connection with the Annual Report of Athlon Energy Inc. ("Athlon") on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission (the "SEC") on the date hereof (the "Report"), I, William B. D. Butler, Chief Financial Officer of Athlon, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

        (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Athlon.

Date: March 7, 2014

/s/ WILLIAM B. D. BUTLER
William B. D. Butler
Vice President—Chief Financial Officer

        A signed original of this written statement required by Section 906 has been provided to Athlon and will be retained by Athlon and furnished to the SEC or its staff upon request.

Note: The certification of the registrant furnished in this exhibit is not deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that Section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the registrant specifically incorporates it by reference.

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Exhibit 32.2

Section 1350 Certification

EX-99.1

Exhibit 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

February 7, 2014

Mr. Robert C. Reeves

CEO and President

Athlon Holdings LP

420 Throckmorton Street, Suite 1200

Fort Worth, TX 76102

Re:	Reserve Evaluation
	Athlon Holdings LP Interests
	Total Proved Reserves
	As of December 31, 2013
	Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and
	Future Net Revenue

Dear Mr. Reeves:

As requested, this report was prepared on February 7, 2014 for Athlon Holdings LP (“Athlon”) for the purpose of submitting our estimates of proved reserves and forecasts of economics attributable to the subject interests. We evaluated 100% of Athlon reserves, which are made up of oil properties in the Spraberry field in the Texas Permian Basin. This report utilized an effective date of December 31, 2013, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). The results of this evaluation are presented in the accompanying tabulation, with a composite summary of the values presented below:

		Proved  Developed  Producing	ProvedDevelopedNon-Producing	ProvedUndeveloped	TotalProved
Net Reserves
Oil	— Mbbl	24,117.7	2,318.3	44,738.4	71,174.4
Gas	— MMcf	50,784.3	4,573.9	96,848.0	152,206.2
NGL	— Mbbl	10,175.5	902.0	19,644.8	30,722.3
Revenue
Oil	— M$	2,224,356.8	213,913.8	4,129,302.0	6,567,571.5
Gas	— M$	167,846.7	14,925.5	318,387.0	501,159.3
NGL	— Mbbl	323,136.4	28,918.8	632,652.3	984,707.2
Severance Taxes	— M$	139,144.2	13,128.4	261,275.8	413,548.4
Ad Valorem Taxes	— M$	64,404.9	6,115.7	120,476.6	190,997.2
Operating Expenses	— M$	697,089.4	51,851.4	1,065,651.1	1,814,591.5
3rd Party COPAS	— M$	2,050.0	1.3	0.0	2,051.3
Investments	— M$	0.0	23,301.0	1,219,515.4	1,242,816.5
Net Operating Income (BFIT)	— M$	1,812,651.6	163,360.2	2,413,422.0	4,389,434.0
Discounted at 10%	— M$	914,921.1	79,722.3	640,858.8	1,635,502.0

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes.  In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

The oil reserves include oil and condensate.  Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for December 31, 2013 were $96.78/bbl and $3.666/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil and gas prices are based upon WTI-Cushing and Henry Hub spot prices, respectively, as published by the EIA for January 1, 2013 through December 1, 2013.

The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $92.27 per barrel for oil and $3.293 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, severance taxes and lease operating expenses were calculated and prepared by Athlon and were reviewed by us for reasonableness. Capital costs for new development wells, production equipment and workovers were scheduled as provided by Athlon. Capital costs were reviewed by us for reasonableness and compared to capital costs provided in previous years. Adjustments were made as necessary after a review with Athlon. Lease operating expenses were either determined at the field or individual well level using averages calculated from historical lease operating statements. All economic parameters, including lease operating expenses and capital costs, were held constant (not escalated) throughout the life of these properties.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Government policies and market conditions different from those employed in this report may cause (1) the total quantity of oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

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This evaluation includes 659 proved undeveloped locations in the Spraberry field in the Texas Permian Basin. Each of these drilling locations proposed as part of Athlon’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Athlon has indicated they have every intent to complete this development plan within the next five years. Furthermore, Athlon has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. 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 Athlon properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. (“CG&A”) Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have not been included.

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data.  The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by Robert D. Ravnaas, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties, Athlon Holdings LP and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the

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circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.

Sincerely,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
/s/ Robert D. Ravnaas, P.E.
Robert D. Ravnaas, P.E.
President

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CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

9601 AMBERGLEN BLVD., SUITE 117	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1106	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

Professional Qualifications of Robert D. Ravnaas, P.E.

President of Cawley, Gillespie & Associates

Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became President in 2011.  He has completed numerous field studies, reserve evaluations and reservoir simulation, waterflood design and monitoring, unit equity determinations and producing rate studies.  He has testified before the Texas Railroad Commission in unitization and field rules hearings.  Prior to CG&A he worked as a Production Engineer for Amoco Production Company. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin.  He is a registered professional engineer in Texas, No. 61304, and a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1)  production performance, (2)  material balance, (3) volumetric and (4)  analogy.  Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data.  However, a large variation exists in the quality, quantity and types of information available on individual properties.  Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc.  As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data.  The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history.  Capacity production can usually be analyzed from graphs of rates versus time or cumulative production.  This procedure is referred to as “decline curve” analysis.  Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components.  Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships.  This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir.  The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids.  Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place.  The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location.  The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir.  Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy.  This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance.  The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods.  Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Cawley, Gillespie & Associates, Inc.

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APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22)Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and 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.

“(i)The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6)Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31)Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category 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.

“(i)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.

“(ii)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.

“(iii)Under no circumstances shall estimates for 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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“(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17)Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S—K.”  This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26)Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects 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 gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

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Fair Value Measurements (Details 5) (Derivative instruments not designated as hedges, Commodity contracts, Derivative fair value loss (gain), USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments not designated as hedges | Commodity contracts | Derivative fair value loss (gain)
Fair value measurements
Amount of Loss (Gain) Recognized in Income	$ 18,115	$ (9,293)	$ 7,959

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Related Party Transactions (Details) (USD $)	12 Months Ended			35 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 07, 2013
Related party transactions
Termination fee	$ 2,408,000
Distribution paid to Holdings' Class A limited partners	75,000,000
Number of common stock exchangeable against each unit	1
Percentage of income tax benefits distributable to holders of New Holdings Units	85.00%
Apollo
Related party transactions
Transaction fee as a percentage of total equity contributed	2.00%
Transaction fees				7,500,000
Consulting and advisory fee as percentage of EBITDAX under first condition	1.00%
Advisory fee per quarter under second condition	62,500
Maximum advisory fee per calendar year	500,000
Advisory fee	500,000	493,000	411,000
Termination fee	2,400,000
Unreimbursed fee on termination of the service agreement	132,000
Apollo Global Securities, LLC
Related party transactions
Proceeds from gross spread	500,000
Payment of discounts and commissions to underwriters in IPO	900,000
Apollo funds
Related party transactions
Distribution paid to Holdings' Class A limited partners	73,000,000
Management team and certain employees
Related party transactions
Distribution paid to Holdings' Class A limited partners	$ 2,000,000
Number of common stock exchangeable against each unit	1

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Employment Benefit Plans (Details) (USD $)	0 Months Ended	12 Months Ended
	Aug. 07, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
401(k) Plan
Employers contributions		$ 585,000	$ 454,000	$ 219,000
Incentive award plan
Non-cash equity-based compensation expense		5,307,000	152,000	106,000
2013 Incentive Award Plan
Incentive award plan
Aggregate shares of common stock available for issuance under the 2013 stock incentive plan		8,400,000
Remaining shares available for grant		7,761,087
Non-cash equity-based compensation expense		4,000,000
Capitalized non-cash equity-based compensation expense		263,000
2013 Incentive Award Plan | RSUs
Incentive award plan
Vesting period of RSU's		3 years
Unvested RSUs
Granted (in shares)		638,913
Weighted - Average Grant Date Fair Value
Granted (in dollars per share)		$ 34.88
Outstanding at end of the period (in dollars per share)		$ 34.88
Additional disclosure
Unvested RSUs subject to variable accounting (in shares)		0
Total unrecognized compensation cost related to unvested RSU's		16,600,000
Weighted-average period for recognition of unrecognized compensation cost		2 years 7 months 6 days
2013 Incentive Award Plan | RSUs | Vesting of awards subject to time and continued employment condition
Unvested RSUs
Outstanding at end of the period (in shares)		411,413
Additional disclosure
Unvested RSUs granted, vesting of which is dependent on passage of specified time and continued employment condition (in shares)		411,413
Vesting of awards in 2014 (in shares)		137,138
Vesting of awards in 2015 (in shares)		137,138
Vesting of awards in 2016 (in shares)		137,137
Outstanding RSUs		411,413
2013 Incentive Award Plan | RSUs | Vesting of awards subject to time, continued employment and performance condition
Unvested RSUs
Outstanding at end of the period (in shares)		227,500
Additional disclosure
Unvested RSUs granted, vesting of which is dependent on passage of specified time and continued employment and also on performance condition (in shares)		227,500
Vesting of awards in 2014 (in shares)		75,834
Vesting of awards in 2015 (in shares)		75,833
Vesting of awards in 2016 (in shares)		75,833
Outstanding RSUs		227,500
Percentage of maximum number of shares that could be earned under the performance-based awards		50.00%
Percentage of designated target vesting levels under the performance-based awards		100.00%
Maximum | 2013 Incentive Award Plan
Incentive award plan
Aggregate shares of common stock available for issuance under the 2013 stock incentive plan at January 1, 2014 under first condition		12,000,000
Percentage increase to shares of common stock available for issuance under the 2013 stock incentive plan at January 1, 2014 under second condition		4.00%
Maximum | 2013 Incentive Award Plan | Non-employee directors
Incentive award plan
Grant date fair value of awards		700,000
Holdings | Class B limited partners
Incentive award plan
Non-cash equity-based compensation expense	1,500,000	1,300,000	152,000	106,000
Capitalized non-cash equity-based compensation expense		$ 415,000	$ 93,000

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Summary of Significant Accounting Policies (Details 2) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended	12 Months Ended
	Aug. 07, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Noncontrolling interest
Noncontrolling interest		$ 10,788
Number of common stock exchangeable against each unit		1
Net income (loss) attributable to noncontrolling interest		1,359
Effects of changes in Athlon's partnership interest in Holdings on Athlon's equity
Net income attributable to stockholders		58,435	53,014	(1,129)
Transfer from noncontrolling interest:
Shares of common stock in public offering	15,789,474
Athlon Holdings GP LLC
Noncontrolling interest
Ownership interest in general partner of Holdings (as a percent)		100.00%
Holdings
Noncontrolling interest
Percentage of ownership interest of management and certain employees (as a percent)	3.20%	2.20%
Effects of changes in Athlon's partnership interest in Holdings on Athlon's equity
Net income attributable to stockholders		59,063
Transfer from noncontrolling interest:
Increase in Athlon's paid-in capital for corporate reorganization		292,549
Increase in Athlon's paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering		295,498
Shares of common stock in public offering		15,789,474
Net transfer from noncontrolling interest		588,047
Change from net income attributable to stockholders and transfers from noncontrolling interest		$ 647,110
Holdings | Class A limited partners
Noncontrolling interest
Percentage of ownership interest of management and certain employees (as a percent)	3.20%	2.20%
Exchange Agreement Number of New Units Exchangeable Against Limited Partner Interest	1,855,563
Number of common stock exchangeable against each unit		1

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Long-Term Debt.

Schedule of quarterly commitment fee on unused portion of the Credit Agreement and applicable margin for Eurodollar and base rate loans

Ratio of Outstanding Borrowings to Borrowing Base	Unused Commitment Fee			Applicable Margin for Eurodollar Loans			Applicable Margin for Base Rate Loans
Less than or equal to .30 to 1		0.375	%		1.50	%		0.50	%
Greater than .30 to 1 but less than or equal to .60 to 1		0.375	%		1.75	%		0.75	%
Greater than .60 to 1 but less than or equal to .80 to 1		0.50	%		2.00	%		1.00	%
Greater than .80 to 1 but less than or equal to .90 to 1		0.50	%		2.25	%		1.25	%
Greater than .90 to 1		0.50	%		2.50	%		1.50	%

Schedule of long-term debt maturities

	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Credit Agreement	$	—	$	—	$	—	$	—	$	—	$	—	$	—
73/8% Senior Notes		500,000		—		—		—		—		—		500,000
Total	$	500,000	$	—	$	—	$	—	$	—	$	—	$	500,000

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Long-Term Debt (Details) (USD $)	12 Months Ended			1 Months Ended		12 Months Ended					12 Months Ended					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 30, 2013 Senior notes	Dec. 31, 2013 Senior notes	Dec. 31, 2013 Senior notes Upon assets disposition triggering events	Dec. 31, 2013 Senior notes Prior to April 15, 2016	Dec. 31, 2013 Senior notes Prior to April 15, 2016 Redemption from proceeds of certain equity offerings	Dec. 31, 2013 Senior notes On or prior to July 15, 2014 Redemption of debt instrument upon change of control	Dec. 31, 2013 Senior notes Maximum	Dec. 31, 2013 Senior notes Maximum Prior to April 15, 2016 Redemption from proceeds of certain equity offerings	Dec. 31, 2013 Credit agreement	Nov. 30, 2013 Credit agreement	May 31, 2013 Credit agreement	Apr. 30, 2013 Credit agreement	Dec. 31, 2013 Credit agreement Applicable Margin for Eurodollar Loans Eurodollar rate	Dec. 31, 2013 Credit agreement Applicable Margin for Eurodollar Loans LIBOR	Dec. 31, 2013 Credit agreement Applicable Margin for Base Rate Loans Eurodollar rate	Dec. 31, 2013 Credit agreement Applicable Margin for Base Rate Loans LIBOR	Dec. 31, 2013 Credit agreement Applicable Margin for Base Rate Loans Base Rate	Dec. 31, 2013 Credit agreement Applicable Margin for Base Rate Loans Prime rate	Dec. 31, 2013 Credit agreement Applicable Margin for Base Rate Loans Federal funds rate	Dec. 31, 2013 Credit agreement Less than or equal to .30 to 1	Dec. 31, 2013 Credit agreement Less than or equal to .30 to 1 Applicable Margin for Eurodollar Loans	Dec. 31, 2013 Credit agreement Less than or equal to .30 to 1 Applicable Margin for Base Rate Loans	Dec. 31, 2013 Credit agreement Greater than .30 to 1 but less than or equal to .60 to 1	Dec. 31, 2013 Credit agreement Greater than .30 to 1 but less than or equal to .60 to 1 Applicable Margin for Eurodollar Loans	Dec. 31, 2013 Credit agreement Greater than .30 to 1 but less than or equal to .60 to 1 Applicable Margin for Base Rate Loans	Dec. 31, 2013 Credit agreement Greater than .60 to 1 but less than or equal to .80 to 1	Dec. 31, 2013 Credit agreement Greater than .60 to 1 but less than or equal to .80 to 1 Applicable Margin for Eurodollar Loans	Dec. 31, 2013 Credit agreement Greater than .60 to 1 but less than or equal to .80 to 1 Applicable Margin for Base Rate Loans	Dec. 31, 2013 Credit agreement Greater than .80 to 1 but less than or equal to .90 to 1	Dec. 31, 2013 Credit agreement Greater than .80 to 1 but less than or equal to .90 to 1 Applicable Margin for Eurodollar Loans	Dec. 31, 2013 Credit agreement Greater than .80 to 1 but less than or equal to .90 to 1 Applicable Margin for Base Rate Loans	Dec. 31, 2013 Credit agreement Greater than .90 to 1	Dec. 31, 2013 Credit agreement Greater than .90 to 1 Applicable Margin for Eurodollar Loans	Dec. 31, 2013 Credit agreement Greater than .90 to 1 Applicable Margin for Base Rate Loans	Dec. 31, 2013 Credit agreement Maximum Less than or equal to .30 to 1	Dec. 31, 2013 Credit agreement Maximum Greater than .30 to 1 but less than or equal to .60 to 1	Dec. 31, 2013 Credit agreement Maximum Greater than .60 to 1 but less than or equal to .80 to 1	Dec. 31, 2013 Credit agreement Maximum Greater than .80 to 1 but less than or equal to .90 to 1	Dec. 31, 2013 Credit agreement Maximum Greater than .90 to 1	Dec. 31, 2013 Credit agreement Minimum Greater than .30 to 1 but less than or equal to .60 to 1	Dec. 31, 2013 Credit agreement Minimum Greater than .60 to 1 but less than or equal to .80 to 1	Dec. 31, 2013 Credit agreement Minimum Greater than .80 to 1 but less than or equal to .90 to 1	Dec. 31, 2013 Former second lien term loan
Long-term debt
Aggregate principal amount of notes issued				$ 500,000,000
Interest rate (as a percent)				7.375%
Distribution paid to Holdings' Class A limited partners	75,000,000			75,000,000
Fixed charge coverage ratio										2.0
Percentage of aggregate principal amount of notes that can be redeemed											35.00%
Redemption price of debt instrument (as a percent)						101.00%	100.00%	107.375%	110.00%
Write off of unamortized debt issuance costs																																														2,800,000
Maximum amount committed by lender												1,000,000,000
Current borrowing base												525,000,000	525,000,000	320,000,000	267,500,000
Outstanding borrowings												0
Outstanding letters of credit												0
Ratio of Outstanding Borrowings to Borrowing Base																																						0.30	0.60	0.80	0.90	0.90	0.30	0.60	0.80
Unused Commitment Fee (as a percent)																							0.375%			0.375%			0.50%			0.50%			0.50%
Applicable Margin (as a percent)																		1.00%				0.50%		1.50%	0.50%		1.75%	0.75%		2.00%	1.00%		2.25%	1.25%		2.50%	1.50%
Variable interest rate base																Eurodollar rate	LIBOR	Eurodollar rate	LIBOR	Base Rate	prime rate	Federal fund
Ratio of consolidated total debt to EBITDAX beginning with quarter ended June 30, 2013												4.75
Ratio of consolidated total debt to EBITDAX beginning with quarter ended June 30, 2014												4.5
Maximum projected production that can be hedged (as a percent)												85.00%
Period over which hedging limitation requirement of the projected production from proved reserve is required to be maintained												66 months
Long-Term Debt Maturities
Thereafter	500,000,000				500,000,000
Total	$ 500,000,000				$ 500,000,000
Weighted-average interest rate (as a percent)	7.60%	4.30%	3.80%

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Fair Value Measurements (Details 3) (Master netting agreements, BNP Paribas, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Master netting agreements | BNP Paribas
Counterparty risk
Fair Market Value of Oil Derivative Contracts Committed	$ 1,082

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Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating leases, payments due by period
Total	$ 1,316,000
2014	467,000
2015	471,000
2016	378,000
Operating lease rental expense	490,000	507,000	272,000
Minimum
Leases
Non-cancelable lease terms	1 year
Corporate office lease
Operating leases, payments due by period
Total	1,031,000
2014	375,000
2015	375,000
2016	281,000
Midland office lease
Operating leases, payments due by period
Total	285,000
2014	92,000
2015	96,000
2016	$ 97,000

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Acquisitions

12 Months Ended

Dec. 31, 2013

Acquisitions

Acquisitions

Note 3. Acquisitions

Element

        On October 3, 2011, Athlon 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's credit agreement and capital contributions from Holdings' partners. The operations of these properties have been included with those of Athlon from the date of acquisition. Athlon incurred approximately $6.4 million of transaction costs related to this acquisition, which are included in "Acquisition costs" in the accompanying Consolidated Statements of Operations. Of this amount, approximately $4.3 million was paid to Apollo. Please read "Note 12. 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):

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

        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.

	Year ended December 31, 2011
	(in thousands, except per share amounts)
Pro forma total revenues	$	89,618
Pro forma net income attributable to stockholders	$	9,777
Pro forma net income per common share:
Basic	$	0.15
Diluted	$	0.14

SandRidge

        On January 6, 2011, Athlon 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's credit agreement and capital contributions from Holdings' partners. The operations of these properties have been included with those of Athlon from the date of acquisition. Athlon incurred $2.6 million of transaction costs related to this acquisition, which are included in "Acquisition costs" in the accompanying Consolidated Statements of Operations. Of this amount, approximately $2.3 million was paid to Apollo. Please read "Note 12. 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):

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

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Stockholders' Equity (Details) (USD $)	0 Months Ended			12 Months Ended
	Aug. 07, 2013	Apr. 26, 2013	Apr. 02, 2013	Dec. 31, 2013
Stockholders' Equity
Common stock issued at incorporation (in shares)			1,000
Aggregate purchase price of common stock issued at incorporation (in dollars)			$ 10.00
Common stock issued in connection with corporate reorganization to certain holders of Class A and Class B limited partner interests in Holdings (in shares)		960,907
Issue price of IPO (in dollars per share)	$ 20.00
Stock split ratio	65.266			65.266
Outstanding common stock shares prior to closing of IPO	66,339,615
Shares of common stock issued in IPO	15,789,474
Net proceeds from IPO, after deducting underwriting discounts and commissions and offering expenses (in dollars)	$ 295,700,000			$ 295,697,000
Preferred Stock
Preferred stock, shares authorized				50,000,000
Preferred stock, shares issued				0
Preferred stock, shares outstanding				0
Holdings
Stockholders' Equity
Shares of common stock issued in IPO				15,789,474
Stockholders' equity
Percentage of ownership noncontrolling interest	3.20%			2.20%

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Summary of the remaining non-cancelable future payments under these operating leases

	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Corporate office lease	$	1,031	$	375	$	375	$	281	$	—	$	—	$	—
Midland office lease		285		92		96		97		—		—		—
Total	$	1,316	$	467	$	471	$	378	$	—	$	—	$	—

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Employment Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Employment Benefit Plans

Summary of changes in unvested RSUs

	Number of Shares		Weighted-Average Grant Date Fair Value Per Share
Outstanding at January 1		—	$	—
Granted		638,913		34.88
Vested		—		—
Forfeited		—		—
Outstanding at December 31		638,913		34.88

Vesting of awards subject to time and continued employment condition

Incentive award plan

Schedule of vesting of RSUs

	Year of Vesting
Year of Grant	2014		2015		2016		Total
2013		137,138		137,138		137,137		411,413

Vesting of awards subject to time, continued employment and performance condition

Incentive award plan

Schedule of vesting of RSUs

	Year of Vesting
Year of Grant	2014		2015		2016		Total
2013		75,834		75,833		75,833		227,500

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Taxes (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Federal:
Current	$ 1,135
Deferred	17,022
Total federal	18,157
State, net of federal benefit:
Deferred	993	1,928	470
Total state	993	1,928	470
Income tax provision	19,150	1,928	470
Reconciliation of income tax benefit (provision) with income tax at the Federal statutory rate
Income (loss) before income taxes	79,572	54,942	(659)
Less: net income prior to corporate reorganization	(27,320)
Less: net income attributable to noncontrolling interest	(1,359)
Income (loss) before income taxes and noncontrolling interest subsequent to corporate reorganization	50,893	54,942	(659)
Income taxes at the Federal statutory rate	17,813
State income taxes, net of federal benefit	933	549	21
Provision to return adjustment	59
Permanent and other	345	1,379	449
Income tax provision	19,150	1,928	470
Assets:
Derivative fair value loss	480
Total current deferred tax assets	480
Liabilities:
Prepaid insurance	(100)	(8)
Derivative fair value gain		(50)
Total current deferred tax liabilities	(100)	(58)
Net current deferred tax asset (liability)	380
Assets:
Alternative minimum tax credits	1,135
Derivative fair value loss	2,080	60
Net operating loss carryforward	43,164
Asset retirement obligations	519	8
Deferred equity-based compensation	1,406
Acquisition cost capitalized	3,351	95
Other	1,840	25
Total long-term deferred tax assets	53,495	188
Liabilities:
Book basis of oil and natural gas properties in excess of tax basis	(145,892)	(2,528)
Total long-term deferred tax liabilities	(145,892)	(2,528)
Net long-term deferred tax liability	(92,397)	(2,340)
Federal
Carryforwards and credits
Federal AMT Credits	1,135
Federal NOL	123,325
2031 | Federal
Carryforwards and credits
Federal NOL	2,433
2032 | Federal
Carryforwards and credits
Federal NOL	77,749
2033 | Federal
Carryforwards and credits
Federal NOL	43,143
Indefinite | Federal
Carryforwards and credits
Federal AMT Credits	$ 1,135

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Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2013

Subsequent events

Summary of open commodity derivative contracts

Period	Average Daily Swap Volume		Weighted- Average Swap Price		Asset (Liability) Fair Market Value
	(Bbl)		(per Bbl)		(in thousands)
2014		7,950	$	92.67	$	(8,354	)
2015		1,300		93.18		2,330
					$	(6,024	)

Subsequent event

Subsequent events

Summary of open commodity derivative contracts

The following table summarizes Athlon's open commodity derivative contracts as of March 7, 2014:

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
2014		9,369		92.61
Q1 2015		4,300		91.29
Q2 2015		4,300		91.29
Q3 2015		1,300		93.18
Q4 2015		1,300		93.18
2015		2,788		91.74

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Formation of the Company and Description of Business (Details) (USD $)	0 Months Ended	12 Months Ended
	Aug. 07, 2013	Dec. 31, 2013	Apr. 26, 2013
Formation of the Company and Description of Business
Tax impact of corporate reorganization			$ 71,600,000
Initial public offering
Shares of common stock issued in IPO	15,789,474
Per share price (in dollars per share)	$ 20.00
Net proceeds from IPO, after deducting underwriting discounts and commissions and offering expenses (in dollars)	$ 295,700,000	$ 295,697,000
Number of common stock exchangeable against each unit		1
Holdings
Initial public offering
Shares of common stock issued in IPO		15,789,474
Holdings | Class A limited partners
Initial public offering
Exchange Agreement Number of New Units Exchangeable Against Limited Partner Interest	1,855,563
Number of common stock exchangeable against each unit		1

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 2. Summary of Significant Accounting Policies

Principles of Consolidation

        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.

Use of Estimates

        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

        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:

	Year ended December 31,
	2013		2012		2011
	(in thousands)
Cash paid during the period for:
Interest	$	25,220	$	8,326	$	2,395
Income taxes		—		—		—

Accounts Receivable

        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, 2013 and 2012, Athlon did not have an allowance for doubtful accounts.

Inventory

        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:

	December 31,
	2013		2012
	(in thousands)
Materials and supplies	$	429	$	670
Oil inventory		499		352
Total inventory	$	928	$	1,022

Oil and Natural Gas Properties

        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 unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated 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 unevaluated 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 properties are included in the full cost pool as incurred; otherwise, they are allocated to various unevaluated leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

        Independent petroleum engineers estimate Athlon's proved reserves annually as of 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.

        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 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.

        Athlon capitalizes interest on expenditures made in connection with exploratory 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 2013 and 2012, Athlon capitalized approximately $0.3 million and $0.2 million, respectively, of interest expense. During 2011, Athlon did not capitalize any 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 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 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 therefore has 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.

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

	December 31,
	2013		2012
	(in thousands)
Evalauted leasehold costs	$	448,689	$	376,271
Wells and related equipment—completed		748,900		379,036
Wells and related equipment—in process		46,589		33,264
Total evaluated	$	1,244,178	$	788,571

Asset Retirement Obligations

        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 drilled well is completing or a well is 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.

        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, 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.

Equity-Based Compensation

        Athlon accounts for equity-based compensation according to the "Share-Based Payment" topic of the ASC, which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. Please read "Note 9. Employee Benefit Plans" for additional discussion of Athlon's employee benefit plans.

        The "Share-Based Payment" topic of the ASC also requires that the benefits associated with the tax deductions in excess of recognized compensation cost, if any, be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. Athlon recognizes compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

Segment Reporting

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

Major Customers / Concentration of Credit Risk

        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:

	Percentage of Total Revenues for the Year Ended December 31,									Outstanding Accounts Receivable Balance as of December 31,
Purchaser	2013			2012			2011			2013			2012
										(in thousands)
Occidental Petroleum Corporation		27	%		29	%		58	%	$	11,673		$	4,456
DCP Midstream			(a)		12	%		13	%			(a)		2,604
High Sierra Crude Oil & Marketing, LLC(b)		46	%		43	%		13	%		18,951			9,348

(a)

Less than 10% for the period indicated.

(b)

Formerly Pecos Gathering & Marketing.

Income Taxes

        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 effected a corporate reorganization. Holdings, Athlon's accounting predecessor, is a partnership not subject to federal income tax. Pursuant to 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.

Revenue Recognition

        Revenues from the sale of oil, natural gas, and NGLs are recognized when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller's price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured. Because final settlement of our hydrocarbon sales can take up to two months, sales volumes and prices are estimated and accrued using information available at the time the revenue is recorded. 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, 2013 and 2012, 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 insignificant.

Derivatives

        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 under Athlon's credit agreement.

        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 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.

Noncontrolling Interest

        As of December 31, 2013, management and certain 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 December 31, 2013 of approximately $10.8 million represents management and certain 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 attributable to noncontrolling interest" for 2013 of approximately $1.4 million represents the net income of Holdings attributable to management and certain 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 2013 (in thousands):

Net income attributable to stockholders	$	59,063
Transfer from noncontrolling interest:
Increase in Athlon's paid-in capital for corporate reorganization		292,549
Increase in Athlon's paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering		295,498
Net transfer from noncontrolling interest		588,047
Change from net income attributable to stockholders and transfers from noncontrolling interest	$	647,110

Earnings Per Share

        For purposes of calculating earnings per share ("EPS"), Athlon allocates net income (loss) to its shareholders and participating securities each quarter under the provisions of the "Earnings Per Share" topic of the ASC. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in distributions with common shares. For purposes of calculating EPS, unvested restricted stock units are considered participating securities. Net income (loss) per common share is calculated by dividing the shareholders' interest in net income (loss), after deducting the interests of participating securities, by the weighted average common shares outstanding.

New Accounting Pronouncements

        In December 2011, the FASB 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 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 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 consolidated financial statements.

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Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash paid during the period for:
Interest	$ 25,220,000	$ 8,326,000	$ 2,395,000
Income taxes	0	0	0
Inventory
Materials and supplies	429,000	670,000
Oil inventory	499,000	352,000
Total inventory	928,000	1,022,000
Oil and Natural Gas Properties
Gain or loss recognized on sales and abandonments of oil and natural gas properties	0
Minimum percentage of sale of proved reserve quantities for significant alteration	25.00%
Interest expense capitalized	300,000	200,000
Discount rate (as a percent)	10.00%
Period used in calculation of ceiling limitation	12 months
Evaluated, including wells and related equipment
Evaluated leasehold costs	448,689,000	376,271,000
Wells and related equipment - completed	748,900,000	379,036,000
Wells and related equipment - in process	46,589,000	33,264,000
Total evaluated	1,244,178,000	788,571,000
Major Customers / Concentration of Credit Risk
Outstanding accounts receivable	48,238,000	24,501,000
Revenue Recognition
Maximum period for final settlement of hydrocarbon sales	2 months
Revenues | Purchaser | Occidental Petroleum Corporation
Major Customers / Concentration of Credit Risk
Percentage of total revenues	27.00%	29.00%	58.00%
Revenues | Purchaser | DCP Midstream
Major Customers / Concentration of Credit Risk
Percentage of total revenues		12.00%	13.00%
Revenues | Purchaser | Pecos Gathering & Marketing
Major Customers / Concentration of Credit Risk
Percentage of total revenues	46.00%	43.00%	13.00%
Accounts Receivable | Purchaser | Occidental Petroleum Corporation
Major Customers / Concentration of Credit Risk
Outstanding accounts receivable	11,673,000	4,456,000
Accounts Receivable | Purchaser | DCP Midstream
Major Customers / Concentration of Credit Risk
Outstanding accounts receivable		2,604,000
Accounts Receivable | Purchaser | Pecos Gathering & Marketing
Major Customers / Concentration of Credit Risk
Outstanding accounts receivable	$ 18,951,000	$ 9,348,000

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Fair Value Measurements (Details 6) (Commodity contracts, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Hierarchy
Increase (decrease) in net commodity derivative assets (liabilities)	$ (39,000)	$ 125,000
Recurring | Net Asset (Liability) | Oil
Fair Value Hierarchy
Total		3,989,000
Recurring | Net Asset (Liability) | Oil | Swaps
Fair Value Hierarchy
Total	(6,024,000)	4,069,000
Recurring | Net Asset (Liability) | Oil | Collars
Fair Value Hierarchy
Total		(80,000)
Recurring | Significant Other Observable Inputs (Level 2) | Oil
Fair Value Hierarchy
Total		3,989,000
Recurring | Significant Other Observable Inputs (Level 2) | Oil | Swaps
Fair Value Hierarchy
Total	(6,024,000)	4,069,000
Recurring | Significant Other Observable Inputs (Level 2) | Oil | Collars
Fair Value Hierarchy
Total		$ (80,000)

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 113,025	$ 8,871
Accounts receivable	48,238	24,501
Derivatives, at fair value		2,246
Inventory	928	1,022
Deferred taxes	380
Other	1,166	2,486
Total current assets	163,737	39,126
Oil and natural gas properties and equipment, at cost - full cost method:
Evaluated, including wells and related equipment	1,244,178	788,571
Unevaluated	89,859	89,860
Accumulated depletion, depreciation, and amortization	(160,779)	(73,824)
Oil and natural gas properties and equipment, net	1,173,258	804,607
Derivatives, at fair value	2,330	2,854
Debt issuance costs	14,679	4,418
Other	1,447	1,293
Total assets	1,355,451	852,298
Accounts payable:
Trade	459	3,170
Affiliate		935
Accrued liabilities:
Lease operating	6,563	3,858
Production, severance, and ad valorem taxes	2,550	1,307
Development capital	68,059	39,483
Interest	7,790	834
Derivatives, at fair value	8,354	592
Revenue payable	20,513	9,330
Deferred taxes		58
Other	4,035	1,808
Total current liabilities	118,323	61,375
Derivatives, at fair value		519
Asset retirement obligations, net of current portion	6,795	5,049
Long-term debt	500,000	362,000
Deferred taxes	92,397	2,340
Other	101	138
Total liabilities	717,616	431,421
Commitments and contingencies
Equity:
Partners' equity		420,877
Preferred stock, $.01 par value, at December 31, 2013, 50,000,000 shares authorized, none issued and outstanding
Common stock, $.01 par value, at December 31, 2013, 500,000,000 shares authorized, 82,129,089 issued and outstanding	821
Additional paid-in capital	593,943
Retained earnings	32,283
Total stockholders' equity	627,047
Noncontrolling interest	10,788
Total equity	637,835	420,877
Total liabilities and equity	$ 1,355,451	$ 852,298

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Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended	12 Months Ended
	Aug. 07, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Apr. 30, 2013
Earnings Per Share
Outstanding common stock prior to consummation of IPO (in shares)					960,907
Issue price of IPO (in dollars per share)	$ 20.00
Stock split ratio	65.266	65.266
Outstanding common stock shares prior to closing of IPO	66,339,615
Conversion of units into common stock		1
Numerator:
Undistributed net income (loss) attributable to stockholders		$ 59,063	$ 53,014	$ (1,129)
Participation rights of unvested RSUs in undistributed earnings		(628)
Basic undistributed net income (loss) attributable to stockholders		58,435	53,014	(1,129)
Denominator:
Basic weighted average shares outstanding		72,915,000	66,340,000	66,340,000
Basic EPS attributable to stockholders (in dollars per share)		$ 0.80	$ 0.80	$ (0.02)
Numerator:
Undistributed net income (loss) attributable to stockholders		59,063	53,014	(1,129)
Participation rights of unvested RSUs in undistributed earnings, diluted		(613)
Effect of conversion of New Holdings Units to shares of Athlon's common stock		1,359
Diluted undistributed net income (loss) attributable to stockholders		$ 59,809	$ 53,014	$ (1,129)
Denominator:
Basic weighted average shares outstanding		72,915,000	66,340,000	66,340,000
Effect of conversion of New Holdings Units to shares of Athlon's common stock		1,856,000	1,856,000
Diluted weighted average shares outstanding		74,771,000	68,196,000	66,340,000
Diluted EPS attributable to stockholders (in dollars per share)		$ 0.80	$ 0.78	$ (0.02)
Antidilutive New Holdings Units excluded from EPS calculations (in shares)				1,855,563

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:
Consolidated net income (loss)	$ 60,422	$ 53,014	$ (1,129)
Adjustments to reconcile consolidated net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization	87,171	54,456	19,747
Deferred taxes	18,015	1,928	470
Non-cash derivative loss (gain)	10,013	(9,947)	7,509
Equity-based compensation	5,307	152	106
Other	5,575	1,758	963
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(24,534)	(7,320)	(16,963)
Other current assets	(71)	(337)	(1,691)
Other assets			(16)
Accounts payable	(2,583)	(2,140)	537
Accrued interest	6,956	578	256
Revenue payable	10,681	3,620	5,710
Derivatives			(1,950)
Other current liabilities	6,685	(460)	5,323
Net cash provided by operating activities	183,637	95,302	18,872
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(54,136)	(80,602)	(414,759)
Development of oil and natural gas properties	(369,946)	(266,235)	(57,457)
Monetization of put options			7,625
Other	(664)	(422)	(884)
Net cash used in investing activities	(424,746)	(347,259)	(465,475)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs	628,992	519,672	198,651
Payments on long-term debt	(505,926)	(331,000)	(31,000)
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	295,697
Capital contributions	1,500	40,166	303,976
Other		(40)
Net cash provided by financing activities	345,263	228,798	471,627
Increase (decrease) in cash and cash equivalents	104,154	(23,159)	25,024
Cash and cash equivalents, beginning of period	8,871	32,030	7,006
Cash and cash equivalents, end of period	$ 113,025	$ 8,871	$ 32,030

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Fair Value Measurements (Details) (Level 1 input, USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Level 1 input
Fair value measurements
Senior notes	$ 522.8

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2013

Element

Acquisitions

Schedule of allocation of purchase price to the fair value of assets acquired and liabilities assumed

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

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

Schedule of unaudited pro forma condensed financial data

	Year ended December 31, 2011
	(in thousands, except per share amounts)
Pro forma total revenues	$	89,618
Pro forma net income attributable to stockholders	$	9,777
Pro forma net income per common share:
Basic	$	0.15
Diluted	$	0.14

SandRidge

Acquisitions

Schedule of allocation of purchase price to the fair value of assets acquired and liabilities assumed

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

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

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Fair Value Measurements (Details 2) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended
	Oct. 31, 2011	Jan. 31, 2011	Sep. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Open commodity derivative contracts	Dec. 31, 2012 Open commodity derivative contracts	Dec. 31, 2013 Open commodity derivative contracts 2014	Dec. 31, 2013 Open commodity derivative contracts 2015	Mar. 31, 2014 Commodity derivative contracts with swap price 2014 bbl	Mar. 31, 2014 Commodity derivative contracts with swap price 2015 bbl
Summary of open commodity derivative contracts
Average Daily Swap Volume											7,950	1,300
Weighted-Average Swap Price											92.67	93.18
Asset (Liability) Fair Market Value							$ (6,024,000)	$ 3,989,000	$ (8,354,000)	$ 2,330,000
Net proceeds from monetization of put options		7,600,000				7,625,000
Interest expense			200,000	36,669,000	9,951,000	2,945,000
Initial payment of premiums	$ 2,000,000

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations

Summary of changes in asset retirement obligations

	Year Ended December 31,
	2013			2012
	(in thousands)
Balance at January 1	$	5,049		$	3,704
Liabilities assumed in acquisitions		395			60
Liabilities incurred from new wells		1,013			815
Liabilities settled		(283	)		—
Accretion of discount		675			478
Revisions of previous estimates		6			(8	)
Balance at December 31		6,855			5,049
Less: current portion		60			—
Asset retirement obligations—long-term	$	6,795		$	5,049

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Formation of the Company and Description of Business

12 Months Ended

Dec. 31, 2013

Formation of the Company and Description of Business

Formation of the Company and Description of Business

Note 1. Formation of the Company and Description of Business

        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 $71.6 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, L.P. ("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") and Holdings' management team and certain employees owned all of the Class A limited partner interests in Holdings and 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 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.

Initial Public Offering

        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 $295.7 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". 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 (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.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
Common stock, par value (in dollars per share)	$ 0.01
Common stock, shares authorized	500,000,000
Common stock, shares issued	82,129,089
Common stock, shares outstanding	82,129,089

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies

Commitments and Contingencies

Note 11. Commitments and Contingencies

Leases

        Athlon leases certain office space that has non-cancelable lease terms in excess of one year. The following table summarizes the remaining non-cancelable future payments under these operating leases as of December 31, 2013:

	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Corporate office lease	$	1,031	$	375	$	375	$	281	$	—	$	—	$	—
Midland office lease		285		92		96		97		—		—		—
Total	$	1,316	$	467	$	471	$	378	$	—	$	—	$	—

        Athlon's operating lease rental expense was approximately $490,000, $507,000, and $272,000 during 2013, 2012, and 2011, respectively.

Litigation

        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.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 07, 2014	Aug. 02, 2013
Document and Entity Information
Entity Registrant Name	Athlon Energy Inc.
Entity Central Index Key	0001574648
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 410,526,324
Entity Common Stock, Shares Outstanding		82,129,089
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions

Related Party Transactions

Note 12. Related Party Transactions

Transaction Fee Agreement

        Athlon was a party to a Transaction Fee Agreement, dated August 23, 2010, which required it 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 an affiliate, Apollo Global Securities, LLC. Upon the consummation of Athlon's IPO, the Transaction Fee Agreement was terminated. Since Athlon's 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.

Services Agreement

        Athlon was a party to a Services Agreement, dated August 23, 2010, which required it 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 2013, 2012, and 2011, Athlon incurred approximately $500,000, $493,000, and $411,000, respectively, of Advisory Fees, which are included in "General and administrative expenses" in the accompanying Consolidated Statements of Operations.

        Upon the consummation of Athlon's IPO, the Services Agreement was terminated and Athlon paid a termination fee of $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, Athlon also agreed to indemnify Apollo and its affiliates and their respective limited partners, general partners, directors, members, officers, managers, employees, agents, advisors, 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.

Distribution

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

Exchange Agreement

        Upon the consummation of its IPO, Athlon entered into an exchange agreement with its management team and certain employees who hold New Holdings Units. 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.

Tax Receivable Agreement

        Upon the consummation of its IPO, Athlon entered into a tax receivable agreement with its management team and certain employees who hold New Holdings Units 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.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:
Oil	$ 252,606	$ 128,081	$ 51,193
Natural gas	16,620	8,415	3,521
Natural gas liquids	30,147	20,615	10,967
Total revenues	299,373	157,111	65,681
Production:
Lease operating	33,776	25,503	13,328
Production, severance, and ad valorem taxes	19,048	10,438	4,727
Processing, gathering, and overhead	222	84	60
Depletion, depreciation, and amortization	87,171	54,456	19,747
General and administrative	21,331	9,678	7,724
Contract termination fee	2,408
Acquisition costs	421	876	9,519
Derivative fair value loss (gain)	18,115	(9,293)	7,959
Accretion of discount on asset retirement obligations	675	478	344
Total expenses	183,167	92,220	63,408
Operating income	116,206	64,891	2,273
Other income (expenses):
Interest	(36,669)	(9,951)	(2,945)
Other	35	2	13
Total other expenses	(36,634)	(9,949)	(2,932)
Income (loss) before income taxes	79,572	54,942	(659)
Income tax provision	19,150	1,928	470
Consolidated net income (loss)	60,422	53,014	(1,129)
Less: net income attributable to noncontrolling interest	1,359
Net income (loss) attributable to stockholders	$ 59,063	$ 53,014	$ (1,129)
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.80	$ 0.80	$ (0.02)
Diluted (in dollars per share)	$ 0.80	$ 0.78	$ (0.02)
Weighted average common shares outstanding:
Basic (in shares)	72,915	66,340	66,340
Diluted (in shares)	74,771	68,196	66,340

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Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-Term Debt.

Long-Term Debt

Note 6. Long-Term Debt

Senior Notes

        In April 2013, Athlon 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 Athlon's credit agreement, to repay in full and terminate Athlon's former second lien term loan, to make a $75 million distribution to Holdings' Class A limited partners, and for general corporate 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 Athlon's ability to:

• •

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

  •

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

  •

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

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

        Under the indenture, starting on April 15, 2016, Athlon 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, Athlon 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 Athlon's option, prior to April 15, 2016, Athlon 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, Athlon 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 Athlon 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, up 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, Athlon's former second lien term loan was paid off and retired and the borrowing base of Athlon's 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 2013.

Credit Agreement

        Athlon is a party to an amended and restated credit agreement dated March 19, 2013 (the "Credit Agreement"), which matures on March 19, 2018. The 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 Credit Agreement is $1.0 billion. Availability under the 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 Credit Agreement was reduced to $267.5 million. In May 2013, Athlon amended the Credit Agreement to, among other things, increase the borrowing base to $320 million. In November 2013, Athlon amended the Credit Agreement to, among other things, increase the borrowing base to $525 million. As of December 31, 2013, the borrowing base was $525 million and there were no outstanding borrowings and no outstanding letters of credit under the Credit Agreement.

        Obligations under the 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 Credit Agreement are guaranteed by Athlon's operating subsidiaries.

        Loans under the 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 Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table. Athlon also incurs a quarterly commitment fee on the unused portion of the Credit Agreement indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	Unused Commitment Fee			Applicable Margin for Eurodollar Loans			Applicable Margin for Base Rate Loans
Less than or equal to .30 to 1		0.375	%		1.50	%		0.50	%
Greater than .30 to 1 but less than or equal to .60 to 1		0.375	%		1.75	%		0.75	%
Greater than .60 to 1 but less than or equal to .80 to 1		0.50	%		2.00	%		1.00	%
Greater than .80 to 1 but less than or equal to .90 to 1		0.50	%		2.25	%		1.25	%
Greater than .90 to 1		0.50	%		2.50	%		1.50	%

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

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

• •

  a prohibition against incurring debt, subject to permitted exceptions;

  •

  a restriction on creating liens on Athlon's assets and the assets of its operating subsidiaries, subject to permitted exceptions;

  •

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

• •

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

  •

  a requirement that Athlon maintain a ratio of consolidated total debt to EBITDAX (as defined in the Credit Agreement) of not more than 4.75 to 1.0 (which ratio changes to 4.5 to 1.0 beginning with the quarter ending June 30, 2014); and

  •

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

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

Long-Term Debt Maturities

        The following table shows Athlon's long-term debt maturities as of December 31, 2013:

	Payments Due by Period
	Total		2014		2015		2016		2017		2018		Thereafter
	(in thousands)
Credit Agreement	$	—	$	—	$	—	$	—	$	—	$	—	$	—
73/8% Senior Notes		500,000		—		—		—		—		—		500,000
Total	$	500,000	$	—	$	—	$	—	$	—	$	—	$	500,000

        During 2013, 2012, and 2011, the weighted-average interest rate for total indebtedness was 7.6%, 4.3%, and 3.8%, respectively.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations

Asset Retirement Obligations

Note 5. 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 Athlon's asset retirement obligations for the periods indicated:

	Year Ended December 31,
	2013			2012
	(in thousands)
Balance at January 1	$	5,049		$	3,704
Liabilities assumed in acquisitions		395			60
Liabilities incurred from new wells		1,013			815
Liabilities settled		(283	)		—
Accretion of discount		675			478
Revisions of previous estimates		6			(8	)
Balance at December 31		6,855			5,049
Less: current portion		60			—
Asset retirement obligations—long-term	$	6,795		$	5,049

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Measurements

Summary of open commodity derivative contracts

Period	Average Daily Swap Volume		Weighted- Average Swap Price		Asset (Liability) Fair Market Value
	(Bbl)		(per Bbl)		(in thousands)
2014		7,950	$	92.67	$	(8,354	)
2015		1,300		93.18		2,330
					$	(6,024	)

Schedule of committed 10% or greater (in terms of fair market value) of oil derivative contracts in asset positions from counterparties, or their affiliates

Counterparty	Fair Market Value of Oil Derivative Contracts Committed
	(in thousands)
BNP Paribas	$	1,082

Schedule of fair value of derivative instruments not designated as hedging instruments

Balance Sheet Location	Oil Commodity Derivatives			Commodity Derivatives Netting(a)			Total Commodity Derivatives
	(in thousands)
As of December 31, 2013
Assets
Derivatives—current	$	143		$	(143	)	$	—
Derivatives—noncurrent		2,330			—			2,330
Total assets		2,473			(143	)		2,330
Liabilities
Derivatives—current		(8,497	)		143			(8,354	)
Derivatives—noncurrent		—			—			—
Total liabilities		(8,497	)		143			(8,354	)
Net liabilities	$	(6,024	)	$	—		$	(6,024	)
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

(a)

Represents counterparty netting under master netting agreements, which allow for netting of commodity derivative contracts. These derivative instruments are reflected net on the accompanying Consolidated Balance Sheets.

Schedule of effect of derivative instruments not designated as hedges on accompanying consolidated statements of operation

		Amount of Loss (Gain) Recognized in Income
		Year ended December 31,
	Location of Loss (Gain) Recognized in Income
Derivatives Not Designated as Hedges		2013		2012			2011
		(in thousands)
Commodity derivative contracts	Derivative fair value loss (gain)	$	18,115	$	(9,293	)	$	7,959

Schedule of assets and liabilities that accounted for at fair value on a recurring basis

	Fair Value Measurements at Reporting Date Using
Description		Net Asset (Liability)			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, 2013
Oil derivative contracts—swaps		$	(6,024	)	$	—	$	(6,024	)	$	—
As of December 31, 2012
Oil derivative contracts—swaps		$	4,069		$	—	$	4,069		$	—
Oil derivative contracts—collars			(80	)		—		(80	)		—
Total		$	3,989		$	—	$	3,989		$	—

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Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events

Subsequent Events

Note 13. Subsequent Events

        Subsequent to December 31, 2013, Athlon entered into additional oil swaps. The following table summarizes Athlon's open commodity derivative contracts as of March 7, 2014:

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
2014		9,369		92.61
Q1 2015		4,300		91.29
Q2 2015		4,300		91.29
Q3 2015		1,300		93.18
Q4 2015		1,300		93.18
2015		2,788		91.74

        On February 6, 2014, Athlon completed the acquisition of certain oil and natural gas properties and related assets in the Midland Basin of West Texas for approximately $88 million in cash (subject to customary post-closing adjustments), pursuant to a Purchase and Sale Agreement dated January 10, 2014 with an effective date of September 1, 2013. Athlon also agreed to acquire additional working interests in the properties, partially offset by the exercise of certain preferential rights, with the net effect of an $8.7 million purchase price increase. The acquisition was financed through cash on hand and borrowings under the Credit Agreement.

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Earnings Per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share

Earnings Per Share

Note 9. Earnings Per Share

        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 is akin to a stock split and has been treated as such in Athlon's 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) attributable to stockholders and EPS computations for the periods indicated:

	Year ended December 31,
	2013			2012		2011
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	59,063		$	53,014	$	(1,129	)
Participation rights of unvested RSUs in undistributed earnings		(628	)		—		—
Basic undistributed net income (loss) attributable to stockholders	$	58,435		$	53,014	$	(1,129	)
Denominator:
Basic weighted average shares outstanding		72,915			66,340		66,340
Basic EPS attributable to stockholders	$	0.80		$	0.80	$	(0.02	)
Diluted EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	59,063		$	53,014	$	(1,129	)
Participation rights of unvested RSUs in undistributed earnings		(613	)		—		—
Effect of conversion of New Holdings Units to shares of Athlon's common stock		1,359			—		—
Diluted undistributed net income (loss) attributable to stockholders	$	59,809		$	53,014	$	(1,129	)
Denominator:
Basic weighted average shares outstanding		72,915			66,340		66,340
Effect of conversion of New Holdings Units to shares of Athlon's common stock(a)		1,856			1,856		—
Diluted weighted average shares outstanding		74,771			68,196		66,340
Diluted EPS attributable to stockholders	$	0.80		$	0.78	$	(0.02	)

(a)

For 2011, 1,855,563 New Holdings Units were outstanding but excluded from the EPS calculations because their effect would have been antidilutive.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2013

Stockholders' Equity

Stockholders' Equity

Note 7. Stockholders' Equity

        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. These securities were offered and sold by Athlon in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act of 1933. On April 26, 2013, in connection with the corporate reorganization, 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. These securities were offered and sold by Athlon in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act of 1933. 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 $295.7 million, after deducting underwriting discounts and commissions and offering expenses. Athlon used the net proceeds from the IPO (i) to reduce outstanding borrowings under the Credit Agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes. 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%.

Preferred Stock

        Athlon's authorized capital stock includes 50,000,000 shares of preferred stock, none of which were issued and outstanding at December 31, 2013. Athlon does not plan to issue any shares of preferred stock.

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Taxes

12 Months Ended

Dec. 31, 2013

Taxes

Taxes

Note 8. Taxes

Income Taxes

        As a result of the corporate reorganization on April 26, 2013, Athlon (a C-corporation) obtained most of the interests in Holdings. Prior to April 26, 2013, Holdings, Athlon's accounting predecessor, was a limited partnership not subject to federal income taxes.

        The components of income tax provision were as follows for the periods indicated:

	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Federal:
Current	$	1,135	$	—	$	—
Deferred		17,022		—		—
Total federal		18,157		—		—
State, net of federal benefit:
Deferred		993		1,928		470
Total state		993		1,928		470
Income tax provision	$	19,150	$	1,928	$	470

        The following table reconciles income tax provision with income tax at the Federal statutory rate for the periods indicated:

	Year Ended December 31,
	2013			2012		2011
	(in thousands)
Income (loss) before income taxes	$	79,572		$	54,942	$	(659	)
Less: net income prior to corporate reorganization		(27,320	)		—		—
Less: net income attributable to noncontrolling interest		(1,359	)		—		—
Income (loss) before income taxes and noncontrolling interest subsequent to corporate reorganization	$	50,893		$	54,942	$	(659	)
Income taxes at the Federal statutory rate	$	17,813		$	—	$	—
State income taxes, net of federal benefit		933			549		21
Provision to return adjustment		59			—		—
Permanent and other		345			1,379		449
Income tax provision	$	19,150		$	1,928	$	470

        The major components of net current deferred taxes and net long-term deferred taxes were as follows as of the dates indicated:

	December 31,
	2013			2012
	(in thousands)
Current:
Assets:
Derivative fair value loss	$	480		$	—
Total current deferred tax assets		480			—
Liabilities:
Prepaid insurance		(100	)		(8	)
Derivative fair value gain		—			(50	)
Total current deferred tax liabilities		(100	)		(58	)
Net current deferred tax asset (liability)	$	380		$	(58	)
Long-term:
Assets:
Alternative minimum tax credits	$	1,135		$	—
Derivative fair value loss		2,080			60
Net operating loss carryforward		43,164			—
Asset retirement obligations		519			8
Deferred equity-based compensation		1,406			—
Acquisition costs capitalized		3,351			95
Other		1,840			25
Total long-term deferred tax assets		53,495			188
Liabilities:
Book basis of oil and natural gas properties in excess of tax basis		(145,892	)		(2,528	)
Total long-term deferred tax liabilities		(145,892	)		(2,528	)
Net long-term deferred tax liability	$	(92,397	)	$	(2,340	)

        At December 31, 2013, Athlon had federal net operating loss ("NOL") carryforwards, which are available to offset future federal state taxable income, if any. At December 31, 2013, Athlon also had federal alternative minimum tax ("AMT") credits, which are available to reduce future federal regular tax liabilities in excess of AMT. Athlon believes it is more likely than not that the NOL carryforwards will offset future taxable income prior to their expiration. The AMT credits have no expiration. Therefore, a valuation allowance against these deferred tax assets is not considered necessary. If unused, these carryforwards and credits will expire as follows:

Expiration Date	Federal AMT Credits		Federal NOL
	(in thousands)
2031	$	—	$	2,433
2032		—		77,749
2033		—		43,143
Indefinite		1,135		—
	$	1,135	$	123,325

        During 2013, 2012, and 2011, Athlon did not have any interest assessed by the taxing authorities or incur any penalties related to income taxes.

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Employment Benefit Plans

12 Months Ended

Dec. 31, 2013

Employment Benefit Plans

Employment Benefit Plans

Note 10. Employment Benefit Plans

401(k) Plan

        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 $585,000, $454,000, and $219,000 during 2013, 2012, and 2011, respectively. Athlon's 401(k) plan does not allow employees to invest in securities of Athlon.

Incentive Award Plan

        In August 2013, Athlon adopted the Athlon Energy Inc. 2013 Incentive Award Plan (the "Plan"). 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. 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 the 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.

        The aggregate number of shares of common stock available for issuance pursuant to awards granted under the Plan is 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:

• •

  shares subject to awards or portions of awards granted under the Plan which are forfeited, expire, or lapse for any reason, or are settled for cash without the delivery of shares, to the extent of such forfeiture, expiration, lapse, or cash settlement; and

  •

  shares that Athlon repurchases prior to vesting so that such shares are returned to Athlon.

        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 December 31, 2013, there were 7,761,087 shares available for issuance under the Plan. During 2013, Athlon recorded non-cash stock-based compensation expense related to the Plan of $4.0 million, 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 2013, Athlon also capitalized $263,000 of non-cash stock-based compensation expense related to the Plan as a component of "Evaluated, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

        RSUs vest over three years, subject to the relative performance of Athlon's stock to that of a designated peer group for Athlon's management team. The following table summarizes the changes in Athlon's unvested RSUs for 2013 (presented at the target level):

	Number of Shares		Weighted-Average Grant Date Fair Value Per Share
Outstanding at January 1		—	$	—
Granted		638,913		34.88
Vested		—		—
Forfeited		—		—
Outstanding at December 31		638,913		34.88

        During 2013, Athlon issued 411,413 RSUs to employees and non-employee directors, the vesting of which is dependent only on the passage of time and continued employment. The following table provides information regarding Athlon's outstanding RSUs at December 31, 2013 the vesting of which is dependent only on the passage of time and continued employment:

	Year of Vesting
Year of Grant	2014		2015		2016		Total
2013		137,138		137,138		137,137		411,413

        During 2013, Athlon also issued 227,500 RSUs to Athlon's management team, the vesting of which is dependent not only on the passage of time and continued employment, but also on the relative performance of Athlon's stock to that of a designated peer group. One-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the number of shares will be earned if the higher maximum target levels are met. If performance is below the designated minimum levels for all performance targets, no performance-based shares will be earned. Performance-based awards were valued using a Monte Carlo simulation. The following table provides information regarding Athlon's outstanding RSUs at December 31, 2013 (presented at the target level) the vesting of which is dependent not only on the passage of time and continued employment, but also on the relative performance of Athlon's stock to that of a designated peer group:

	Year of Vesting
Year of Grant	2014		2015		2016		Total
2013		75,834		75,833		75,833		227,500

        None of Athlon's unvested RSUs are subject to variable accounting. As of December 31, 2013, Athlon had approximately $16.6 million of total unrecognized compensation cost related to unvested RSUs, which is expected to be recognized over a weighted-average period of approximately 2.6 years.

Class B Interests

        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 the 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, 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 2013, 2012, and 2011, Athlon recorded approximately $1.3 million, $152,000, and $106,000, 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 2013 and 2012, Athlon capitalized approximately $415,000 and $93,000, respectively, of non-cash stock-based compensation expense as a component of "Evaluated, including wells and related equipment" in the accompanying Consolidated Balance Sheets.

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Acquisitions (Details) (USD $)	0 Months Ended	12 Months Ended		0 Months Ended
	Oct. 03, 2011 Element	Dec. 31, 2011 Element	Oct. 03, 2011 Element Apollo	Jan. 06, 2011 SandRidge	Jan. 06, 2011 SandRidge Apollo
Acquisitions
Cash paid for acquisition	$ 253,200,000			$ 156,000,000
Transaction costs incurred	6,400,000		4,300,000	2,600,000	2,300,000
Allocation of the purchase price to the fair value of the assets acquired and liabilities assumed
Proved properties, including wells and related equipment	130,527,000			158,157,000
Unproved properties	123,107,000
Other assets	806,000
Oil inventory				637,000
Total assets acquired	254,440,000			158,794,000
Current liabilities	831,000
Asset retirement obligations	393,000			2,778,000
Total liabilities assumed	1,224,000
Fair value of net assets acquired	253,216,000			156,016,000
Unaudited pro forma condensed financial data
Pro forma total revenues		89,618,000
Pro forma net income attributable to stockholders		$ 9,777,000
Pro forma net income (loss) per common share:
Basic (in dollar per share)		$ 0.15
Diluted (in dollar per share)		$ 0.14

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Schedule of supplemental disclosures of cash flow information

	Year ended December 31,
	2013		2012		2011
	(in thousands)
Cash paid during the period for:
Interest	$	25,220	$	8,326	$	2,395
Income taxes		—		—		—

Schedule of inventory

	December 31,
	2013		2012
	(in thousands)
Materials and supplies	$	429	$	670
Oil inventory		499		352
Total inventory	$	928	$	1,022

Schedule of evaluated properties, including wells and related equipment

	December 31,
	2013		2012
	(in thousands)
Evalauted leasehold costs	$	448,689	$	376,271
Wells and related equipment—completed		748,900		379,036
Wells and related equipment—in process		46,589		33,264
Total evaluated	$	1,244,178	$	788,571

Schedule of major customers outstanding accounts receivable balance

	Percentage of Total Revenues for the Year Ended December 31,									Outstanding Accounts Receivable Balance as of December 31,
Purchaser	2013			2012			2011			2013			2012
										(in thousands)
Occidental Petroleum Corporation		27	%		29	%		58	%	$	11,673		$	4,456
DCP Midstream			(a)		12	%		13	%			(a)		2,604
High Sierra Crude Oil & Marketing, LLC(b)		46	%		43	%		13	%		18,951			9,348

(a)

Less than 10% for the period indicated.

(b)

Formerly Pecos Gathering & Marketing.

Summary of effects of changes in Athlon's partnership interest in Holdings on Athlon's equity

The following table summarizes the effects of changes in Athlon's partnership interest in Holdings on Athlon's equity for 2013 (in thousands):

Net income attributable to stockholders	$	59,063
Transfer from noncontrolling interest:
Increase in Athlon's paid-in capital for corporate reorganization		292,549
Increase in Athlon's paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering		295,498
Net transfer from noncontrolling interest		588,047
Change from net income attributable to stockholders and transfers from noncontrolling interest	$	647,110

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Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Taxes

Schedule of the components of income tax provision

	Year Ended December 31,
	2013		2012		2011
	(in thousands)
Federal:
Current	$	1,135	$	—	$	—
Deferred		17,022		—		—
Total federal		18,157		—		—
State, net of federal benefit:
Deferred		993		1,928		470
Total state		993		1,928		470
Income tax provision	$	19,150	$	1,928	$	470

Schedule of reconciliation of income tax provision with income tax at the Federal statutory rate

	Year Ended December 31,
	2013			2012		2011
	(in thousands)
Income (loss) before income taxes	$	79,572		$	54,942	$	(659	)
Less: net income prior to corporate reorganization		(27,320	)		—		—
Less: net income attributable to noncontrolling interest		(1,359	)		—		—
Income (loss) before income taxes and noncontrolling interest subsequent to corporate reorganization	$	50,893		$	54,942	$	(659	)
Income taxes at the Federal statutory rate	$	17,813		$	—	$	—
State income taxes, net of federal benefit		933			549		21
Provision to return adjustment		59			—		—
Permanent and other		345			1,379		449
Income tax provision	$	19,150		$	1,928	$	470

Schedule of the major components of net current deferred taxes and net long-term deferred taxes

	December 31,
	2013			2012
	(in thousands)
Current:
Assets:
Derivative fair value loss	$	480		$	—
Total current deferred tax assets		480			—
Liabilities:
Prepaid insurance		(100	)		(8	)
Derivative fair value gain		—			(50	)
Total current deferred tax liabilities		(100	)		(58	)
Net current deferred tax asset (liability)	$	380		$	(58	)
Long-term:
Assets:
Alternative minimum tax credits	$	1,135		$	—
Derivative fair value loss		2,080			60
Net operating loss carryforward		43,164			—
Asset retirement obligations		519			8
Deferred equity-based compensation		1,406			—
Acquisition costs capitalized		3,351			95
Other		1,840			25
Total long-term deferred tax assets		53,495			188
Liabilities:
Book basis of oil and natural gas properties in excess of tax basis		(145,892	)		(2,528	)
Total long-term deferred tax liabilities		(145,892	)		(2,528	)
Net long-term deferred tax liability	$	(92,397	)	$	(2,340	)

Schedule of expiration of carryforwards and credits

Expiration Date	Federal AMT Credits		Federal NOL
	(in thousands)
2031	$	—	$	2,433
2032		—		77,749
2033		—		43,143
Indefinite		1,135		—
	$	1,135	$	123,325

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Subsequent Events (Details) (USD $) In Millions, unless otherwise specified			0 Months Ended
	Mar. 31, 2014 Commodity derivative contracts with swap price 2014 bbl	Mar. 31, 2014 Commodity derivative contracts with swap price 2015 bbl	Feb. 06, 2014 Subsequent event Midland Basin	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q1 2014 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q2 2014 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q3 2014 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q4 2014 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q1 2015 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q2 2015 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q3 2015 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price Q4 2015 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price 2014 Oil bbl	Mar. 07, 2014 Subsequent event Commodity derivative contracts with swap price 2015 Oil bbl
Subsequent events
Average Daily Swap Volume	7,950	1,300		8,606	8,950	9,950	9,950	4,300	4,300	1,300	1,300	9,369	2,788
Weighted-Average Swap Price	92.67	93.18		92.70	92.71	92.52	92.52	91.29	91.29	93.18	93.18	92.61	91.74
Cash paid for acquisition			$ 88.0
Increase in purchase price			$ 8.7

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset retirement obligations
Balance at the beginning of the period	$ 5,049	$ 3,704
Liabilities assumed in acquisitions	395	60
Liabilities incurred from new wells	1,013	815
Liabilities settled	(283)
Accretion of discount	675	478	344
Revisions of previous estimates	6	(8)
Balance at the end of the period	6,855	5,049	3,704
Less: current portion	60
Asset retirement obligations - long-term	$ 6,795	$ 5,049

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Total Stockholders' Equity	Partners' Equity	Common Stock	Additional Paid-in Capital	Retained Earnings	Noncontrolling Interest
Balance at Dec. 31, 2010			$ 24,499
Balance at Dec. 31, 2010	24,499
Increase (Decrease) in Equity
Capital contributions	303,976		303,976
Equity-based compensation prior to corporate reorganization	106		106
Net income (loss) prior to corporate reorganization	(1,129)		(1,129)
Balance at Dec. 31, 2011			327,452
Balance at Dec. 31, 2011	327,452
Increase (Decrease) in Equity
Capital contributions	40,166		40,166
Equity-based compensation prior to corporate reorganization	245		245
Net income (loss) prior to corporate reorganization	53,014		53,014
Balance at Dec. 31, 2012	420,877		420,877
Balance at Dec. 31, 2012	420,877
Increase (Decrease) in Equity
Capital contributions	1,500		1,500
Equity-based compensation prior to corporate reorganization	89		89
Net income (loss) 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		364,817	(374,246)	663	364,154		9,429
Common stock issued in corporate reorganization (in shares)				66,340,000
Tax impact of corporate reorganization	(71,605)	(71,605)			(71,605)
Shares of common stock sold in initial public offering, net of offering costs	295,656	295,656		158	295,498
Shares of common stock sold in initial public offering, net of offering costs (in shares)				15,789,000
Equity-based compensation subsequent to corporate reorganization	5,896	5,896			5,896
Consolidated net income subsequent to corporate reorganization	33,642	32,283				32,283	1,359
Balance at Dec. 31, 2013	$ 637,835	$ 627,047		$ 821	$ 593,943	$ 32,283	$ 10,788
Balance (in shares) at Dec. 31, 2013	82,129,089			82,129,000

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Measurements

Fair Value Measurements

Note 4. Fair Value Measurements

        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 December 31, 2013, the fair value of the senior notes was approximately $522.8 million using open market quotes ("Level 1" input).

Commodity Derivative Contracts

        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, which provide a fixed price for a notional amount of sales volumes. The following table summarizes Athlon's open commodity derivative contracts as of December 31, 2013:

Period	Average Daily Swap Volume		Weighted- Average Swap Price		Asset (Liability) Fair Market Value
	(Bbl)		(per Bbl)		(in thousands)
2014		7,950	$	92.67	$	(8,354	)
2015		1,300		93.18		2,330
					$	(6,024	)

        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 the third quarter of 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, 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:

Counterparty	Fair Market Value of Oil Derivative Contracts Committed
	(in thousands)
BNP Paribas	$	1,082

        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.

Tabular Disclosures of Fair Value Measurements

        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 December 31, 2013
Assets
Derivatives—current	$	143		$	(143	)	$	—
Derivatives—noncurrent		2,330			—			2,330
Total assets		2,473			(143	)		2,330
Liabilities
Derivatives—current		(8,497	)		143			(8,354	)
Derivatives—noncurrent		—			—			—
Total liabilities		(8,497	)		143			(8,354	)
Net liabilities	$	(6,024	)	$	—		$	(6,024	)
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

(a)

Represents counterparty netting under master netting agreements, which allow for netting of commodity derivative contracts. These derivative instruments are reflected net on the accompanying Consolidated Balance Sheets.

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

		Amount of Loss (Gain) Recognized in Income
		Year ended December 31,
	Location of Loss (Gain) Recognized in Income
Derivatives Not Designated as Hedges		2013		2012			2011
		(in thousands)
Commodity derivative contracts	Derivative fair value loss (gain)	$	18,115	$	(9,293	)	$	7,959

Fair Value Hierarchy

        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:

• •

  Level 1—Inputs such as unadjusted, quoted prices that are available in active markets for identical assets or liabilities.

  •

  Level 2—Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable, such as quoted prices for similar assets and liabilities or quoted prices in inactive markets.

  •

  Level 3—Inputs that are unobservable for use when little or no market data exists requiring the use of valuation methodologies that result in management's best estimate of fair value.

        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:

• •

  Level 2—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. Settlement is determined by the average underlying price over a predetermined period of time. Athlon uses observable inputs in an option pricing valuation model to determine fair value such as: (i) current market and contractual prices for the underlying instruments; (ii) quoted forward prices for oil; (iii) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (iv) appropriate volatilities.

        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 $39,000 as of December 31, 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	Net Asset (Liability)			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, 2013
Oil derivative contracts—swaps	$	(6,024	)	$	—	$	(6,024	)	$	—
As of December 31, 2012
Oil derivative contracts—swaps	$	4,069		$	—	$	4,069		$	—
Oil derivative contracts—collars		(80	)		—		(80	)		—
Total	$	3,989		$	—	$	3,989		$	—

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share

Schedule of allocation of net income (loss) attributable to stockholders and EPS computations

	Year ended December 31,
	2013			2012		2011
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	59,063		$	53,014	$	(1,129	)
Participation rights of unvested RSUs in undistributed earnings		(628	)		—		—
Basic undistributed net income (loss) attributable to stockholders	$	58,435		$	53,014	$	(1,129	)
Denominator:
Basic weighted average shares outstanding		72,915			66,340		66,340
Basic EPS attributable to stockholders	$	0.80		$	0.80	$	(0.02	)
Diluted EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	59,063		$	53,014	$	(1,129	)
Participation rights of unvested RSUs in undistributed earnings		(613	)		—		—
Effect of conversion of New Holdings Units to shares of Athlon's common stock		1,359			—		—
Diluted undistributed net income (loss) attributable to stockholders	$	59,809		$	53,014	$	(1,129	)
Denominator:
Basic weighted average shares outstanding		72,915			66,340		66,340
Effect of conversion of New Holdings Units to shares of Athlon's common stock(a)		1,856			1,856		—
Diluted weighted average shares outstanding		74,771			68,196		66,340
Diluted EPS attributable to stockholders	$	0.80		$	0.78	$	(0.02	)

(a)

For 2011, 1,855,563 New Holdings Units were outstanding but excluded from the EPS calculations because their effect would have been antidilutive.

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Fair Value Measurements (Details 4) (Commodity contracts, USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Liabilities
Net assets (liabilities)	$ (6,024)	$ 3,989
Derivative instruments not designated as hedging instruments | Oil
Assets
Oil Commodity Derivatives, assets	2,473	6,651
Commodity Derivatives Netting, assets	(143)	(1,551)
Total Commodity Derivatives	2,330	5,100
Liabilities
Oil Commodity Derivatives, liabilities	(8,497)	(2,662)
Commodity Derivatives Netting, liabilities	143	1,551
Total Commodity Derivatives	(8,354)	(1,111)
Net assets (liabilities)	(6,024)	3,989
Derivative instruments not designated as hedging instruments | Oil | Derivative assets - current
Assets
Oil Commodity Derivatives, assets	143	3,386
Commodity Derivatives Netting, assets	(143)	(1,140)
Total Commodity Derivatives		2,246
Derivative instruments not designated as hedging instruments | Oil | Derivative assets - noncurrent
Assets
Oil Commodity Derivatives, assets	2,330	3,265
Commodity Derivatives Netting, assets		(411)
Total Commodity Derivatives	2,330	2,854
Derivative instruments not designated as hedging instruments | Oil | Derivative liabilities - current
Liabilities
Oil Commodity Derivatives, liabilities	(8,497)	(1,732)
Commodity Derivatives Netting, liabilities	143	1,140
Total Commodity Derivatives	(8,354)	(592)
Derivative instruments not designated as hedging instruments | Oil | Derivative liabilities - noncurrent
Liabilities
Oil Commodity Derivatives, liabilities		(930)
Commodity Derivatives Netting, liabilities		411
Total Commodity Derivatives		$ (519)

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies

Principles of Consolidation

Principles of Consolidation

        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.

Use of Estimates

Use of Estimates

        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

Cash and Cash Equivalents

        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:

	Year ended December 31,
	2013		2012		2011
	(in thousands)
Cash paid during the period for:
Interest	$	25,220	$	8,326	$	2,395
Income taxes		—		—		—

Accounts Receivable

Accounts Receivable

        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, 2013 and 2012, Athlon did not have an allowance for doubtful accounts.

Inventory

Inventory

        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:

	December 31,
	2013		2012
	(in thousands)
Materials and supplies	$	429	$	670
Oil inventory		499		352
Total inventory	$	928	$	1,022

Oil and Natural Gas Properties

Oil and Natural Gas Properties

        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 unevaluated properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unevaluated 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 unevaluated 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 properties are included in the full cost pool as incurred; otherwise, they are allocated to various unevaluated leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

        Independent petroleum engineers estimate Athlon's proved reserves annually as of 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.

        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 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.

        Athlon capitalizes interest on expenditures made in connection with exploratory 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 2013 and 2012, Athlon capitalized approximately $0.3 million and $0.2 million, respectively, of interest expense. During 2011, Athlon did not capitalize any 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 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 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 therefore has 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.

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

	December 31,
	2013		2012
	(in thousands)
Evalauted leasehold costs	$	448,689	$	376,271
Wells and related equipment—completed		748,900		379,036
Wells and related equipment—in process		46,589		33,264
Total evaluated	$	1,244,178	$	788,571

Asset Retirement Obligations

Asset Retirement Obligations

        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 drilled well is completing or a well is 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.

        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, 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.

Equity-Based Compensation

Equity-Based Compensation

        Athlon accounts for equity-based compensation according to the "Share-Based Payment" topic of the ASC, which requires the recognition of compensation expense for equity-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. Please read "Note 9. Employee Benefit Plans" for additional discussion of Athlon's employee benefit plans.

        The "Share-Based Payment" topic of the ASC also requires that the benefits associated with the tax deductions in excess of recognized compensation cost, if any, be reported as a financing cash flow. This requirement reduces net operating cash flows and increases net financing cash flows. Athlon recognizes compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

Segment Reporting

Segment Reporting

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

Major Customers / Concentration of Credit Risk

Major Customers / Concentration of Credit Risk

        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:

	Percentage of Total Revenues for the Year Ended December 31,									Outstanding Accounts Receivable Balance as of December 31,
Purchaser	2013			2012			2011			2013			2012
										(in thousands)
Occidental Petroleum Corporation		27	%		29	%		58	%	$	11,673		$	4,456
DCP Midstream			(a)		12	%		13	%			(a)		2,604
High Sierra Crude Oil & Marketing, LLC(b)		46	%		43	%		13	%		18,951			9,348

(a)

Less than 10% for the period indicated.

(b)

Formerly Pecos Gathering & Marketing.

Income Taxes

Income Taxes

        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 effected a corporate reorganization. Holdings, Athlon's accounting predecessor, is a partnership not subject to federal income tax. Pursuant to 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.

Revenue Recognition

Revenue Recognition

        Revenues from the sale of oil, natural gas, and NGLs are recognized when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the seller's price to the buyer is fixed or determinable; and (iv) collectability is reasonably assured. Because final settlement of our hydrocarbon sales can take up to two months, sales volumes and prices are estimated and accrued using information available at the time the revenue is recorded. 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, 2013 and 2012, 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 insignificant.

Derivatives

Derivatives

        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 under Athlon's credit agreement.

        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 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.

Noncontrolling Interest

Noncontrolling Interest

        As of December 31, 2013, management and certain 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 December 31, 2013 of approximately $10.8 million represents management and certain 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 attributable to noncontrolling interest" for 2013 of approximately $1.4 million represents the net income of Holdings attributable to management and certain 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 2013 (in thousands):

Net income attributable to stockholders	$	59,063
Transfer from noncontrolling interest:
Increase in Athlon's paid-in capital for corporate reorganization		292,549
Increase in Athlon's paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering		295,498
Net transfer from noncontrolling interest		588,047
Change from net income attributable to stockholders and transfers from noncontrolling interest	$	647,110

Earnings Per Share

Earnings Per Share

        For purposes of calculating earnings per share ("EPS"), Athlon allocates net income (loss) to its shareholders and participating securities each quarter under the provisions of the "Earnings Per Share" topic of the ASC. Under the two-class method of calculating EPS, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in distributions with common shares. For purposes of calculating EPS, unvested restricted stock units are considered participating securities. Net income (loss) per common share is calculated by dividing the shareholders' interest in net income (loss), after deducting the interests of participating securities, by the weighted average common shares outstanding.

New Accounting Pronouncements

New Accounting Pronouncements

        In December 2011, the FASB 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 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 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 consolidated financial statements.