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.

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.

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.

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

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.

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.

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.

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:

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

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.

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.

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.

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.

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.

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:

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

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

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.

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.

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.

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

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.

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

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:

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

The following table sets forth information with respect to the number of wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found, or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

	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.

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.

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.

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

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing reserves.

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

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

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.

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

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

our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our results of operations and financial condition, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

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

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

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

that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such "hazardous substances" have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the "CWA"), the 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

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.

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

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

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.

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

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

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil, and NGLs are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state, and local level. These types of regulation include requiring permits for the drilling of wells,

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

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

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

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

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations, and rule makings that significantly fostered competition in the business of

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

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

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

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

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

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

The petroleum industry is also subject to compliance with various other federal, state, and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

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

As of December 31, 2013, we had 70 full-time employees, including four geologists, 13 engineers, and 10 land professionals. Of these full-time employees, 51 are salaried administrative or supervisory employees and 38 work in our corporate headquarters. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory, and other disciplines to assist our full-time employees. We consider our relations with our employees to be satisfactory.

Our 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.

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.

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

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

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

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

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

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

As a recently formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational, and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational, and management resources. The failure to continue to upgrade our technical, administrative, operating, and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers, and other professionals in the oil and natural gas

industry, could have a material adverse effect on our business, financial condition, and results of operations and our ability to timely execute our business plan.

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:

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

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)

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.

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

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:

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

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

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

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

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from purchasers of our oil and natural gas production. For 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

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 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:

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

federal taxation. Accordingly, our Standardized Measure 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.

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

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

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

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

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

We incurred a net loss of $1.1 million for 2011, our first full year of operation, and we may incur net losses in the future. Our development of and participation in 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.

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

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

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

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

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

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

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

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

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.

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.

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.

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.

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

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

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.

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

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

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination

resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health, and safety impacts of our operations. In addition, the risk of accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition, or results of operations could be materially adversely affected.

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

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

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

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

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

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

From time to time legislative proposals are made that would, if enacted, make significant changes to U.S. tax laws. These proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties, and extending the amortization period for certain geological and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

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

The EPA has adopted two sets of related rules, one of which regulates emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the "Tailoring Rule", in May 2010, and it also became effective in January 2011. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage, and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.

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

number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

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

of customers, reduce our ability to obtain financing, and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations, and financial condition.

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

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing, and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process, and sell oil and natural gas, and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

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

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 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:

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.

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

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

The following 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

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

	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.

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".

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.

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.

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".

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.

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

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:

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

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.

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:

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.

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.

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:

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.

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	%

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.

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	%

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

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

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:

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.

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	%

	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	%

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.

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

	Year ended December 31,					Increase / (Decrease)

	2012			2011		$			%
Expenses (in thousands):
Production:
Lease operating(a)	$	25,503		$	13,328	$	12,175			91	%
Production, severance, and ad valorem taxes		10,438			4,727		5,711			121	%
Processing, gathering, and overhead		84			60		24			40	%


Total production expenses		36,025			18,115		17,910			99	%
Other:
Depletion, depreciation, and amortization		54,456			19,747		34,709			176	%
General and administrative		9,678			7,724		1,954			25	%
Acquisition costs		876			9,519		(8,643	)		-91	%
Derivative fair value loss (gain)		(9,293	)		7,959		(17,252	)		-217	%
Accretion of discount on asset retirement obligations		478			344		134			39	%


Total operating		92,220			63,408		28,812			45	%
Interest		9,951			2,945		7,006			238	%
Income tax provision		1,928			470		1,458			310	%


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




Expenses (per BOE):
Production:
Lease operating(a)	$	9.89		$	13.82	$	(3.93	)		-28	%
Production, severance, and ad valorem taxes		4.05			4.90		(0.85	)		-17	%
Processing, gathering, and overhead		0.03			0.06		(0.03	)		-50	%


Total production expenses		13.97			18.78		(4.81	)		-26	%
Other:
Depletion, depreciation, and amortization		21.11			20.48		0.63			3	%
General and administrative		3.75			8.01		(4.26	)		-53	%
Acquisition costs		0.34			9.87		(9.53	)		-97	%
Derivative fair value loss (gain)		(3.60	)		8.26		(11.86	)		-144	%
Accretion of discount on asset retirement obligations		0.19			0.36		(0.17	)		-47	%


Total operating		35.76			65.76		(30.00	)		-46	%
Interest		3.86			3.05		0.81			27	%
Income tax provision		0.75			0.49		0.26			53	%


Total expenses	$	40.37		$	69.30	$	(28.93	)		-42	%

Production expenses. 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

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.

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

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

Our development capital primarily relates to 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.

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:

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.

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.

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.

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,

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

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:

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 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:

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

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

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

Increases in commodity prices may be accompanied by or result in: (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.

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

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

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

Our independent petroleum engineers, CG&A, estimate our proved reserves annually 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.

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.

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.

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

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

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

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

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.

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

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.

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.

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

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

We have elected to "opt out" of this provision and, as a result, we will comply with new or revised accounting standards as required when they are adopted. This decision to opt out of the extended transition period is irrevocable.

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.

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:

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.

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

Due to the volatility of commodity prices, we enter into various derivative instruments to manage and reduce our exposure to price changes. We primarily utilize WTI crude oil swaps that establish a fixed price for the production covered by the swaps. We also have 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.

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:

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 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

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

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.

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.

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.

ATHLON ENERGY INC.

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.

ATHLON ENERGY INC.

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.

ATHLON ENERGY INC.

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.

	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.

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.

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.

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.

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

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

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

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

Accounts receivable, which are primarily from the sale of oil, natural gas, and natural gas liquids ("NGLs"), is accrued based on estimates of the sales and prices Athlon believes it will receive. Athlon routinely reviews outstanding balances, assesses the financial strength of its customers, and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2013 and 2012, Athlon did not have an allowance for doubtful accounts.

Inventory includes materials and supplies that Athlon intends to deploy to various development activities and oil in tanks at the lease, both of which are stated at the lower of cost (determined on an

average basis) or market. Oil in tanks at the lease is carried at an amount equal to its costs to produce. Inventory consisted of the following as of the dates indicated:

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

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.

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.

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:

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.

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.

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.

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:

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.

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.

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.

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):

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.

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.

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):

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

On January 6, 2011, Athlon 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):

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 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:

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:

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

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

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

	(in thousands)
As of 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

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

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

As required by GAAP, Athlon utilizes the most observable inputs available for the valuation technique used. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. Athlon's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions were used to estimate the fair values of Athlon's assets and liabilities that are accounted for at fair value on a recurring basis:

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

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

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:

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.

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:

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 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.

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

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

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%.

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.

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:

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:

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

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	)

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.

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:

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):

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:

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:

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.

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.

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:

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

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.

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.

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.

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.

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.

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.

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:

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.

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

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

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

All of Athlon's results of operations relate to oil and natural gas producing activities. Athlon'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.

Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. Estimates of future net cash flows from Athlon's properties, and the representative value thereof, were made using 12-month first-day-of-the-month oil and natural gas average prices, as adjusted for basis or location differentials, held constant over the life of the reserves. Prices used in estimating Athlon's future net cash flows were as follows as of the dates indicated:

Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. Future cash inflows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and the estimated effect of future income taxes. 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.

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:



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

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

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

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

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

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.

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.

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

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."

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.

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:

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.

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.

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).

		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).

		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.

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.

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.


(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


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)

Title of each class		Name of each exchange on which registered

Common Stock, $0.01 Par Value		New York Stock Exchange


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



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

	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

	High		Low

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

Ratio of Outstanding Borrowings to Borrowing Base

Less than or equal to .30 to 1	0.375	%	1.50	%	0.50	%
Greater than .30 to 1 but less than or equal to .60 to 1	0.375	%	1.75	%	0.75	%
Greater than .60 to 1 but less than or equal to .80 to 1	0.50	%	2.00	%	1.00	%
Greater than .80 to 1 but less than or equal to .90 to 1	0.50	%	2.25	%	1.25	%
Greater than .90 to 1	0.50	%	2.50	%	1.50	%

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	)

		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

	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


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


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


Total assets acquired		254,440


Current liabilities		831
Asset retirement obligations		393


Total liabilities assumed		1,224


Fair value of net assets acquired	$	253,216

	Year ended December 31, 2011

	(in thousands, 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


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

	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


		/s/ Ernst & Young LLP

		Amount of Loss (Gain) Recognized in Income

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

	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

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

		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

	Year of Vesting

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

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

	(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


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

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

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