Athlon Energy (ATHL) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2013

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number: 001-36026

ATHLON ENERGY INC.

(Exact name of registrant as specified in its charter)

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

(817) 984-8200

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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 x  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 x  No o

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

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

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

As of November 14, 2013, we had 82,129,089 outstanding shares of common stock, $0.01 par value, excluding Athlon Holdings LP units exchangeable for 1,855,563 shares of our common stock.

ATHLON ENERGY INC.

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1
	Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	2
	Consolidated Statement of Changes in Equity for the nine months ended September 30, 2013	3
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	37
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 5.	Other Information	38
Item 6.	Exhibits	39

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and our other materials filed with the United States Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements.  These forward-looking statements give our current expectations or forecasts of future events.  Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts.  These statements may include words such as “may”, “will”, “could”, “anticipate”, “estimate”, “expect”, “project”, “intend”, “plan”, “believe”, “should”, “predict”, “potential”, “pursue”, “target”, “continue”, and other words and terms of similar meaning.  You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report.  Our actual results may differ significantly from the results discussed in the forward-looking statements.  Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Risk Factors” in our final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended (the “Securities Act”) on August 5, 2013.  If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected.  We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

i

GLOSSARY

The following are abbreviations and definitions of certain terms used in this Report:

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

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

·Bbl/D.  One Bbl per day.

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

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

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

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

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

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

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

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

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

·FASB.  Financial Accounting Standards Board.

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

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

·GAAP.  Accounting principles generally accepted in the United States.

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

·Holdings.  Athlon Holdings LP, our accounting predecessor.

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

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

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

·LIBOR.  London Interbank Offered Rate.

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

·MBOE.  One thousand barrels of oil equivalent.

·Mcf.  One thousand cubic feet of natural gas.

·MMBOE.  One million barrels of oil equivalent.

·MMcf.  One million cubic feet of natural gas.

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

·MMcfe/D.  One million cubic feet of natural gas equivalent per day.

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

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

·NYMEX.  The New York Mercantile Exchange.

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

ii

·Production margin.  Total wellhead revenues less total production costs.

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

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

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

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

·Proved reserves.  Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, the project within a reasonable time.  For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

iii

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ATHLON ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and par value amounts)

	September 30,			December 31,
	2013			2012
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	196,888		$	8,871
Accounts receivable	45,851			24,501
Derivatives, at fair value	—			2,246
Inventory	972			1,022
Other	1,205			2,486
Total current assets	244,916			39,126
Properties and equipment, at cost - full cost method:
Proved properties, including wells and related equipment	1,084,881			788,571
Unproved properties	110,095			89,860
Accumulated depletion, depreciation, and amortization	(135,689		)	(73,824		)
	1,059,287			804,607
Derivatives, at fair value	1,211			2,854
Debt issuance costs	14,603			4,418
Other	1,400			1,293
Total assets	$	1,321,417		$	852,298
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,338		$	3,170
Affiliate	2			935
Accrued liabilities:
Lease operating	5,391			3,858
Production, severance, and ad valorem taxes	5,362			1,307
Development capital	60,092			39,483
Interest	16,802			834
Derivatives, at fair value	10,185			592
Revenue payable	19,550			9,330
Deferred taxes	14,529			58
Other	2,021			1,808
Total current liabilities	136,272			61,375
Derivatives, at fair value	992			519
Asset retirement obligations, net of current portion	6,439			5,049
Long-term debt	500,000			362,000
Deferred taxes	67,878			2,340
Other	109			138
Total liabilities	711,690			431,421
Commitments and contingencies
Equity:
Partners’ equity	—			420,877
Preferred stock, $.01 par value, at September 30, 2013, 50,000,000 shares authorized, none issued and outstanding	—			—
Common stock, $.01 par value, at September 30, 2013, 500,000,000 shares authorized, 82,189,089 issued and outstanding	821			—
Additional paid-in capital	588,583			—
Retained earnings	10,278			—
Total stockholders’ equity	599,682			—
Noncontrolling interest	10,045			—
Total equity	609,727			420,877
Total liabilities and equity	$	1,321,417		$	852,298

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

1

ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues:
Oil	$	75,666		$	34,357		$	175,934		$	91,407
Natural gas	4,164			2,383			11,894			5,323
Natural gas liquids	8,595			5,346			20,508			14,379
Total revenues	88,425			42,086			208,336			111,109
Expenses:
Production:
Lease operating	8,762			7,205			23,774			17,846
Production, severance, and ad valorem taxes	5,439			2,806			13,380			7,617
Processing, gathering, and overhead	59			29			169			55
Depletion, depreciation, and amortization	23,611			15,091			62,022			37,770
General and administrative	6,725			2,134			13,723			7,212
Contract termination fee	2,408			—			2,408			—
Derivative fair value loss (gain)	27,037			14,268			21,331			(9,590		)
Accretion of discount on asset retirement obligations	174			123			485			343
Total expenses	74,215			41,656			137,292			61,253
Operating income	14,210			430			71,044			49,856
Other income (expenses):
Interest	(10,039		)	(2,602		)	(26,595		)	(5,804		)
Other	30			—			30			2
Total other expenses	(10,009		)	(2,602		)	(26,565		)	(5,802		)
Income (loss) before income taxes	4,201			(2,172		)	44,479			44,054
Income tax provision (benefit)	1,934			(76		)	6,805			1,546
Consolidated net income (loss)	2,267			(2,096		)	37,674			42,508
Less: net income (loss) attributable to noncontrolling interest	(215		)	—			616			—
Net income (loss) attributable to stockholders	$	2,482		$	(2,096	)	$	37,058		$	42,508
Net income (loss) per common share:
Basic	$	0.03		$	(0.03	)	$	0.53		$	0.64
Diluted	$	0.03		$	(0.03	)	$	0.53		$	0.62
Weighted average common shares outstanding:
Basic	76,637			66,340			69,810			66,340
Diluted	78,493			66,340			71,666			68,196

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

2

ATHLON ENERGY INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)

				Athlon Stockholders
				Issued
				Shares of			Additional					Total
	Partners’			Common	Common		Paid-in			Retained		Stockholders’			Noncontrolling		Total
	Equity			Stock	Stock		Capital			Earnings		Equity			Interest		Equity
Balance at December 31, 2012	$	420,877		—	$	—	$	—		$	—	$	—		$	—	$	420,877
Capital contributions	1,500			—	—		—			—		—			—		1,500
Equity-based compensation prior to corporate reorganization	89			—	—		—			—		—			—		89
Net income prior to corporate reorganization	26,780			—	—		—			—		—			—		26,780
Distributions to Athlon Holdings LP’s Class A limited partners	(75,000		)	—	—		—			—		—			—		(75,000		)
Common stock issued in corporate reorganization	(374,246		)	66,340	663		364,154			—		364,817			9,429		—
Tax impact of corporate reorganization	—			—	—		(73,204		)	—		(73,204		)	—		(73,204		)
Equity-based compensation subsequent to corporate reorganization	—			—	—		2,160			—		2,160			—		2,160
Shares of common stock sold in initial public offering, net of offering costs	—			15,789	158		295,473			—		295,631			—		295,631
Consolidated net income subsequent to corporate reorganization	—			—	—		—			10,278		10,278			616		10,894
Balance at September 30, 2013	$	—		82,129	$	821	$	588,583		$	10,278	$	599,682		$	10,045	$	609,727

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

3

ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine months ended September 30,
	2013			2012
Cash flows from operating activities:
Consolidated net income	$	37,674		$	42,508
Adjustments to reconcile consolidated net income to net cash provided by operating activities:
Depletion, depreciation, and amortization	62,022			37,770
Deferred taxes	6,805			1,546
Non-cash derivative loss (gain)	13,955			(11,760		)
Equity-based compensation	1,799			118
Other	4,756			952
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(21,350		)	(7,390		)
Other current assets	(155		)	(975		)
Accounts payable	(702		)	(461		)
Accrued interest	15,968			478
Revenue payable	9,718			3,317
Other current liabilities	6,285			(3,349		)
Net cash provided by operating activities	136,775			62,754
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(36,533		)	(3,290		)
Development of oil and natural gas properties	(257,984		)	(183,327		)
Other	(486		)	(283		)
Net cash used in investing activities	(295,003		)	(186,900		)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs	629,627			425,684
Payments on long-term debt	(505,926		)	(325,000		)
Distributions to Athlon Holdings LP’s Class A limited partners	(75,000		)	—
Shares of common stock sold in initial public offering, net of offering costs	296,044			—
Other	1,500			166
Net cash provided by financing activities	346,245			100,850
Increase (decrease) in cash and cash equivalents	188,017			(23,296		)
Cash and cash equivalents, beginning of period	8,871			32,030
Cash and cash equivalents, end of period	$	196,888		$	8,734

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

4

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1.Formation of the Company and Description of Business

Athlon Energy Inc. (together with its subsidiaries, “Athlon”), a Delaware corporation, was formed on April 1, 2013 and is an independent exploration and production company focused on the acquisition, development, and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin.

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

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

In the corporate reorganization, the Apollo Funds entered into a number of distribution and contribution transactions pursuant to which the Apollo Funds exchanged their Class A limited partner interests in Holdings for common stock of Athlon.  The remaining holders of Class A limited partner interests in Holdings have not exchanged their interests in the reorganization transactions.  In addition, the holders of the Class B limited partner interests in Holdings exchanged their interests for common stock of Athlon subject to the same conditions and vesting terms.

Initial Public Offering

On August 7, 2013, Athlon completed its initial public offering (“IPO”) of 15,789,474 shares of its common stock at $20.00 per share and received net proceeds of approximately $295.6 million, after deducting underwriting discounts and commissions and offering expenses.  Upon closing of the IPO, the limited partnership agreement of Holdings was amended and restated to, among other things, modify Holdings’ capital structure by replacing its different classes of interests with a single new class of units, the “New Holdings Units”.  The members of Holdings’ management team and certain employees that held Class A limited partner interests now own 1,855,563 New Holdings Units and entered into an exchange agreement under which (subject to the terms of the exchange agreement) they have the right to exchange their New Holdings Units for shares of common stock of Athlon on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications.  All other New Holdings Units are held by Athlon.  Athlon used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of Athlon’s purchase of New Holdings Units (i) to reduce outstanding borrowings under its credit agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes, including potential acquisitions.

Note 2.Basis of Presentation

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

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

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

5

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Income Taxes

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

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

In April 2013, Athlon had a corporate reorganization to effectuate its IPO.  Holdings, Athlon’s accounting predecessor, is a partnership not subject to federal income tax.  Pursuant to the steps of the corporate reorganization, certain Class A limited partners and the Class B limited partners of Holdings exchanged their interests for shares of Athlon’s common stock.  Athlon’s operations are now subject to federal income tax.  The tax implications of the corporate reorganization and the tax impact of the conversion to operating as a taxable entity have been reflected in the accompanying consolidated financial statements.

Noncontrolling Interest

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

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

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

	Three months ended September 30, 2013		Nine months ended September 30, 2013
	(in thousands)
Net income attributable to stockholders	$	2,482	$	37,058
Transfer from noncontrolling interest:
Increase in Athlon’s paid-in capital for corporate reorganization	—		290,950
Increase in Athlon’s paid-in capital for issuance of 15,789,474 shares of common stock in initial public offering	295,473		295,473
Net transfer from noncontrolling interest	295,473		586,423
Change from net income attributable to stockholders and transfers from (to) noncontrolling interest	$	297,955	$	623,481

6

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

New Accounting Pronouncements

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

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

Note 3. Proved Properties

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

	September 30,		December 31,
	2013		2012
	(in thousands)
Proved leasehold costs	$	411,657	$	376,271
Wells and related equipment - Completed	634,980		379,036
Wells and related equipment - In process	38,244		33,264
Total proved properties	$	1,084,881	$	788,571

Note 4.  Fair Value Measurements

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

Derivative Policy

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

Athlon applies the provisions of the “Derivatives and Hedging” topic of the Accounting Standards Codification, which requires each derivative instrument to be recorded in the accompanying Consolidated Balance Sheets at fair value.  If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings.  Athlon elected not to designate its current portfolio of commodity derivative contracts as hedges for accounting purposes.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

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

Commodity Derivative Contracts

Commodity prices are often subject to significant volatility due to many factors that are beyond Athlon’s control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters.  Athlon manages oil price risk with swaps and collars.  Swaps provide a fixed

7

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

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

	Average	Weighted -		Average	Weighted -		Average	Weighted -		Asset
	Daily	Average		Daily	Average		Daily	Average		(Liability)
	Floor	Floor		Cap	Cap		Swap	Swap		Fair Market
Period	Volume	Price		Volume	Price		Volume	Price		Value
	(Bbl)	(per Bbl)		(Bbl)	(per Bbl)		(Bbl)	(per Bbl)		(in thousands)
Oct. - Dec. 2013	150	$	75.00	150	$	105.95	7,000	$	95.01	$	(4,205	)
2014	—	—		—	—		7,950	92.67		(7,532		)
2015	—	—		—	—		1,300	93.18		2,101
										$	(9,636	)

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

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

	Fair Market Value of
	Oil Derivative
	Contracts
Counterparty	Committed
	(in thousands)
BNP Paribas	$	458

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.

8

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Tabular Disclosures of Fair Value Measurements

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

	Oil			Commodity			Total
Balance Sheet	Commodity			Derivatives			Commodity
Location	Derivatives			Netting (a)			Derivatives
	(in thousands)
As of September 30, 2013
Assets
Derivatives - current	$	162		$	(162	)	$	—
Derivatives - noncurrent	2,149			(938		)	1,211
Total assets	2,311			(1,100		)	1,211
Liabilities
Derivatives - current	(10,347		)	162			(10,185		)
Derivatives - noncurrent	(1,930		)	938			(992		)
Total liabilities	(12,277		)	1,100			(11,177		)
Net liabilities	$	(9,966	)	$	—		$	(9,966	)
As of December 31, 2012
Assets
Derivatives - current	$	3,386		$	(1,140	)	$	2,246
Derivatives - noncurrent	3,265			(411		)	2,854
Total assets	6,651			(1,551		)	5,100
Liabilities
Derivatives - current	(1,732		)	1,140			(592		)
Derivatives - noncurrent	(930		)	411			(519		)
Total liabilities	(2,662		)	1,551			(1,111		)
Net assets	$	3,989		$	—		$	3,989

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

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

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

Fair Value Hierarchy

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

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

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

9

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

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

·Level 2 — Fair values of swaps are estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services.  Athlon’s collars are average value options.  Settlement is determined by the average underlying price over a predetermined period of time.  Athlon uses observable inputs in an option pricing valuation model to determine fair value such as: (i) current market and contractual prices for the underlying instruments; (ii) quoted forward prices for oil and natural gas; (iii) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (iv) appropriate volatilities.

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

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

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
Description	Asset (liability), net			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
As of September 30, 2013
Oil derivative contracts - swaps	$	(9,622	)	$	—	$	(9,622	)	$	—
Oil derivative contracts - basis differential swaps	(330		)	—		(330		)	—
Oil derivative contracts - collars	(14		)	—		(14		)	—
Total	$	(9,966	)	$	—	$	(9,966	)	$	—
As of December 31, 2012
Oil derivative contracts - swaps	$	4,069		$	—	$	4,069		$	—
Oil derivative contracts - collars	(80		)	—		(80		)	—
Total	$	3,989		$	—	$	3,989		$	—

10

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Note 5. Asset Retirement Obligations

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

Balance at January 1	$	5,049
Liabilities assumed in acquisitions	335
Liabilities incurred from new wells	735
Liabilities settled	(108		)
Accretion of discount	485
Revisions of previous estimates	3
Balance at September 30	6,499
Less: current portion	60
Asset retirement obligations - long-term	$	6,439

Note 6. Long-Term Debt

Senior Notes

In April 2013, Holdings issued $500 million aggregate principal amount of 7 3/8% senior notes due 2021 (the “Notes”).  The net proceeds from the Notes were used to repay a portion of the outstanding borrowings under Holdings’ credit agreement, to repay in full and terminate Holdings’ former second lien term loan, to make a $75 million distribution to Holdings’ Class A limited partners, and for general partnership purposes.  On August 14, 2013, Holdings entered into a supplemental indenture pursuant to which Athlon became an unconditional guarantor of the Notes.

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

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

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

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

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

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

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

11

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Credit Agreement

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

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

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

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

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

The “Eurodollar rate” for any interest period (either one, two, three, or nine months, as selected by Holdings) is the rate equal to the British Bankers Association London Interbank Offered Rate (“LIBOR”) for deposits in dollars for a similar interest period.  The “Base Rate” is calculated as the highest of: (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (ii) the federal funds effective rate plus 0.5%; or (iii) except during a “LIBOR Unavailability Period”, the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0%.

Any outstanding letters of credit reduce the availability under the Holdings Credit Agreement.  Borrowings under the Holdings Credit Agreement may be repaid from time to time without penalty.

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

·a prohibition against incurring debt, subject to permitted exceptions;

·a restriction on creating liens on Holdings’ assets and the assets of its operating subsidiaries, subject to permitted exceptions;

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

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

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

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

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

12

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Note 7. Stockholders’ Equity

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

As discussed in “Note 1. Formation of the Company and Description of Business”, on August 7, 2013, Athlon completed its IPO of 15,789,474 shares of its common stock at $20.00 per share and received net proceeds of approximately $295.6 million, after deducting underwriting discounts and commissions and offering expenses.  Athlon used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of Athlon’s purchase of New Holdings Units (i) to reduce outstanding borrowings under the Holdings Credit Agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes, including potential acquisitions.  Upon consummation of the IPO, Athlon’s ownership percentage of Holdings increased, resulting in a decrease in the noncontrolling interest from approximately 3.2% to approximately 2.2%.

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

Note 8. Earnings Per Share

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

13

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	2,482		$	(2,096	)	$	37,058		$	42,508
Participation rights of unvested RSUs in undistributed earnings	(6		)	—			(6		)	—
Basic undistributed net income (loss) attributable to stockholders	$	2,476		$	(2,096	)	$	37,052		$	42,508
Denominator:
Basic weighted average shares outstanding	76,637			66,340			69,810			66,340
Basic EPS attributable to stockholders	$	0.03		$	(0.03	)	$	0.53		$	0.64
Diluted EPS
Numerator:
Undistributed net income (loss) attributable to stockholders	$	2,482		$	(2,096	)	$	37,058		$	42,508
Participation rights of unvested RSUs in undistributed earnings	(6		)	—			(6		)	—
Effect of conversion of New Holdings Units to shares of Athlon’s common stock	(215		)	—			616			—
Diluted undistributed net income (loss) attributable to stockholders	$	2,261		$	(2,096	)	$	37,668		$	42,508
Denominator:
Basic weighted average shares outstanding	76,637			66,340			69,810			66,340
Effect of conversion of New Holdings Units to shares of Athlon’s common stock (a)	1,856			—			1,856			1,856
Diluted weighted average shares outstanding	78,493			66,340			71,666			68,196
Diluted EPS attributable to stockholders	$	0.03		$	(0.03	)	$	0.53		$	0.62

(a)For the three months ended September 30, 2012, 1,855,563 New Holdings Units were outstanding but excluded from the EPS calculations because their effect would have been antidilutive.

Note 9.  Incentive Stock Plans

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

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

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

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

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

14

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

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

		Weighted -
		Average
	Number of	Grant Date
	Shares	Fair Value
Outstanding at January 1	—	$	—
Granted	623,913	32.21
Vested	—	—
Forfeited	—	—
Outstanding at September 30	623,913	32.21

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

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

Class B Interests

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

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

Note 10. Commitments and Contingencies

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

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

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Note 11. Related Party Transactions

Transaction Fee Agreement

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

Services Agreement

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

Upon the consummation of Athlon’s IPO, Holdings terminated the Services Agreement and, in connection with the termination, Holdings paid $2.4 million (plus $132,000 of unreimbursed fees) to Apollo.  Such payment corresponded to the present value as of the date of termination of the aggregate annual fees that would have been payable during the remainder of the term of the Services Agreement (assuming a term ending on August 23, 2020).  Under the Services Agreement, Holdings also agreed to indemnify Apollo and its affiliates and their respective limited partners, general partners, directors, members, officers, managers, employees, agents, advisors, their directors, officers, and representatives for potential losses relating to the services contemplated under the Services Agreement.

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

Apollo Global Securities, LLC is an affiliate of the Apollo Funds and received a portion of the gross spread as an initial purchaser of the Notes of $0.5 million.  Apollo Global Securities, LLC was also an underwriter in Athlon’s IPO and received a portion of the discounts and commissions paid to the underwriters in the IPO of approximately $0.9 million.

Distribution

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

Exchange Agreement

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

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Tax Receivable Agreement

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

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

Note 12. Subsequent Events

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

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ATHLON ENERGY INC.

Item 2.  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 in “Item 1. Financial Statements”.  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 law.  Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under “Cautionary Note Regarding Forward-Looking Information” and “Risk Factors” in our final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act on August 5, 2013.

Overview

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

We were founded in August 2010 by a group of executives from Encore Acquisition Company following its acquisition by Denbury Resources, Inc.  With an average of approximately 20 years of industry experience and 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.

Initial Public Offering

On August 7, 2013, we completed our IPO of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $295.6 million, after deducting underwriting discounts and commissions and offering expenses.  Upon closing of the IPO, the limited partnership agreement of Holdings was amended and restated to, among other things, modify Holdings’ capital structure by replacing its different classes of interests with a single new class of units, the “New Holdings Units”.  The members of Holdings’ management team and certain employees 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 to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of our purchase of New Holdings Units (i) to reduce outstanding borrowings under its credit agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes, including potential acquisitions.

Factors That Significantly Affect Our Financial Condition and Results of Operations

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

We use commodity derivative instruments, such as swaps and collars to manage and reduce price volatility and other market risks associated with our oil production.  These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases.  Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions.  We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes.  Therefore, changes in fair value of these derivative instruments are recognized in earnings.  Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of our commodity derivative contracts.

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

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

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

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

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

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

·facility or equipment availability and unexpected downtime;

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

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

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

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

Corporate Reorganization.  We were formed on April 1, 2013.  On April 26, 2013, Holdings 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.  The historical consolidated financial statements included herein for periods prior to the reorganization transactions are based on Holdings consolidated financial statements.  As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the reorganization transactions had been completed at the beginning of the periods presented or what our future results of operations are likely to be.

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

Income Taxes.  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.

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Increased Drilling Activity.  We began operations in January 2011 and gradually added operated vertical drilling rigs.  At September 30, 2013, we operated seven vertical drilling rigs and one horizontal rig on our properties.  Our 2013 drilling capital expenditures are expected to be between $380 million and $390 million, plus an additional $15 million for infrastructure, leasing, and capitalized workovers.  We expect to drill 169 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells.  In 2014, we intend to expand to an eight-rig vertical drilling program and a two-rig horizontal drilling program.  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, Holdings issued $500 million in aggregate principal amount of 7 3/8% senior notes due 2021.  We used the proceeds from the 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 our Class A limited partners, and for general partnership purposes.  The Notes bear interest at a rate significantly higher than the rates under our credit agreement which resulted in higher interest expense in periods subsequent to April 2013 as compared to periods prior to April 2013.  In the future, we may incur additional indebtedness to fund our acquisition and development activities.  Please read “—Capital Commitments, Capital Resources, and Liquidity—Liquidity” for additional discussion of our financing arrangements.

Sources of Our Revenues

Our revenues are derived from the sale of oil, natural gas, and NGLs within the continental United States and do not include the effects of derivatives.  For the third quarter of 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:

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Oil
NYMEX WTI High	$	110.53		$	99.00		$	110.53		$	109.77
NYMEX WTI Low	97.99			83.75			86.68			77.69
Differential to Average NYMEX WTI	(1.61		)	(3.91		)	(3.74		)	(5.74		)
Natural Gas
NYMEX Henry Hub High	3.81			3.32			4.41			3.32
NYMEX Henry Hub Low	3.23			2.61			3.11			1.91
Differential to Average NYMEX Henry Hub	(0.30		)	(0.15		)	(0.25		)	(0.13		)

We normally sell production to a relatively small number of customers. If any significant customer decided to stop purchasing oil and natural gas from us, our revenues could decline and our operating results and financial condition could be harmed.  However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our significant customers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Principal Components of Our Cost Structure

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

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

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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.

General and Administrative Expense.  G&A expense consists of company overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, and legal compliance costs.  Upon completion of 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.

How We Evaluate Our Operations

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

·Our oil, natural gas, and NGLs revenues increased 110% to $88.4 million in the third quarter of 2013 as compared to $42.1 million in the third quarter of 2012.

·Our average daily production volumes increased 69% to 12,960 BOE/D in the third quarter of 2013 as compared to 7,673 BOE/D in the third quarter of 2012.  Oil and NGLs represented approximately 82% of our total production volumes in the third quarter of 2013.

·Our average realized oil price increased 18% to $104.21 per Bbl in the third quarter of 2013 as compared to $88.28 per Bbl in the third quarter of 2012, our average realized natural gas price increased 23% to $3.28 per Mcf in the third quarter of 2013 as compared to $2.66 per Mcf in the third quarter of 2012, and our average realized NGL price increased 6% to $33.76 per Bbl in the third quarter of 2013 as compared to $31.90 per Bbl in the third quarter of 2012.

·Our production margin increased 131% to $74.2 million in the third quarter of 2013 as compared to $32.0 million in the third quarter of 2012.  Total wellhead revenues per BOE increased 24% and total production expenses per BOE decreased 16%.  On a per BOE basis, our production margin increased 37% to $62.20 per BOE in the third quarter of 2013 as compared to $45.39 per BOE in the third quarter of 2012.

·We invested $128.0 million in oil and natural gas activities, of which $107.8 million was invested in development and exploration activities, yielding 46 gross (45 net) productive wells, and $20.1 million was invested in acquisitions of oil and natural gas properties.

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

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Results of Operations

Comparison of Quarter Ended September 30, 2013 to Quarter Ended September 30, 2012

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

	Three months ended September 30,				Increase / (Decrease)
	2013		2012		$		%
Revenues (in thousands):
Oil	$	75,666	$	34,357	$	41,309	120	%
Natural gas	4,164		2,383		1,781		75	%
NGLs	8,595		5,346		3,249		61	%
Total revenues	$	88,425	$	42,086	$	46,339	110	%
Average realized prices:
Oil ($/Bbl) (excluding impact of cash settled derivatives)	$	104.21	$	88.28	$	15.93	18	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	94.39	$	89.03	$	5.36	6	%
Natural gas ($/Mcf)	$	3.28	$	2.66	$	0.62	23	%
NGLs ($/Bbl)	$	33.76	$	31.90	$	1.86	6	%
Combined ($/BOE) (excluding impact of cash settled derivatives)	$	74.16	$	59.62	$	14.54	24	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	68.18	$	60.03	$	8.15	14	%
Total production volumes:
Oil (MBbls)	726		389		337		87	%
Natural gas (MMcf)	1,270		895		375		42	%
NGLs (MBbls)	255		168		87		52	%
Combined (MBOE)	1,192		706		486		69	%
Average daily production volumes:
Oil (Bbls/D)	7,893		4,230		3,663		87	%
Natural gas (Mcf/D)	13,804		9,724		4,080		42	%
NGLs (Bbls/D)	2,767		1,822		945		52	%
Combined (BOE/D)	12,960		7,673		5,287		69	%

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

	Three months ended September 30,
	2013			2012
Average realized oil price ($/Bbl)	$	104.21		$	88.28
Average NYMEX ($/Bbl)	$	105.82		$	92.19
Differential to NYMEX	$	(1.61	)	$	(3.91	)
Average realized oil price to NYMEX percentage	98		%	96		%
Average realized natural gas price ($/Mcf)	$	3.28		$	2.66
Average NYMEX ($/Mcf)	$	3.58		$	2.81
Differential to NYMEX	$	(0.30	)	$	(0.15	)
Average realized natural gas price to NYMEX percentage	92		%	95		%

Our average realized oil price as a percentage of the average NYMEX price improved to 98% for the third quarter of 2013 as compared to 96% for the third quarter of 2012, primarily due to the alleviation of certain capacity constraints between the Midland Basin, Cushing, Oklahoma, and Gulf Coast refineries.  Our average realized natural gas price as a percentage of the average NYMEX price remained relatively constant at 92% for the third quarter of 2013 as compared to 95% for the third quarter of 2012.

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Oil revenues increased 120% to $75.7 million in the third quarter of 2013 from $34.4 million in the third quarter of 2012 as a result of an increase in our oil production volumes of 337 MBbls and a $15.93 per Bbl increase in our average realized oil price.  Our higher oil production increased oil revenues by $29.7 million and was primarily the result of our development program in the Permian Basin.  Our higher average realized oil price increased oil revenues by $11.6 million and was primarily due to a higher average NYMEX price, which increased to $105.82 per Bbl in the third quarter of 2013 from $92.19 per Bbl in the third quarter of 2012, and the tightening of our oil differentials as previously discussed.

Natural gas revenues increased 75% to $4.2 million in the third quarter of 2013 from $2.4 million in the third quarter of 2012 as a result of an increase in our natural gas production volumes of 375 MMcf and a $0.62 per Mcf increase in our average realized natural gas price.  Our higher average realized natural gas price increased natural gas revenues by $0.8 million and was primarily due to a higher average NYMEX price, which increased to $3.58 per Mcf in the third quarter of 2013 from $2.81 per Mcf in the third quarter of 2012.  Our higher natural gas production increased natural gas revenues by $1.0 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring a portion of our natural gas production as either (i) our well is not yet tied into the third-party gathering system, (ii) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported, or (iii) our production is prorated due to high demand on the third-party gathering system.  During the third quarter of 2013, we estimate that we flared approximately 4.4 MMcfe/D net, which included both residue gas and NGL production.  We expect to continue flaring until further improvements can be made to various third-party gathering systems, which are scheduled to be completed early in the fourth quarter of 2013.

NGL revenues increased 61% to $8.6 million in the third quarter of 2013 from $5.3 million in the third quarter of 2012 as a result of an increase in our NGL production volumes of 87 MBbls and a $1.86 per Bbl increase in our average realized NGL price.  Our higher NGL production increased NGL revenues by $2.8 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring as described above.  Our higher average realized NGL price increased NGL revenues by $0.5 million.

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

	Three months ended September 30,					Increase / (Decrease)
	2013		2012			$			%
Expenses (in thousands):
Production:
Lease operating (a)	$	8,762	$	7,205		$	1,557		22	%
Production, severance, and ad valorem taxes	5,439		2,806			2,633			94	%
Processing, gathering, and overhead	59		29			30			103	%
Total production expenses	14,260		10,040			4,220			42	%
Other:
Depletion, depreciation, and amortization	23,611		15,091			8,520			56	%
General and administrative	6,725		2,134			4,591			215	%
Contract termination fee	2,408		—			2,408			N/A
Derivative fair value loss	27,037		14,268			12,769			89	%
Accretion of discount on asset retirement obligations	174		123			51			41	%
Total operating	74,215		41,656			32,559			78	%
Interest	10,039		2,602			7,437			286	%
Income tax provision (benefit)	1,934		(76		)	2,010			-2645	%
Total expenses	$	86,118	$	44,182		$	42,006		95	%
Expenses (per BOE):
Production:
Lease operating (a)	$	7.35	$	10.21		$	(2.86	)	-28	%
Production, severance, and ad valorem taxes	4.56		3.98			0.58			15	%
Processing, gathering, and overhead	0.05		0.04			0.01			25	%
Total production expenses	11.96		14.23			(2.27		)	-16	%
Other:
Depletion, depreciation, and amortization	19.80		21.38			(1.58		)	-7	%
General and administrative	5.64		3.02			2.62			87	%
Contract termination fee	2.02		—			2.02			N/A
Derivative fair value loss	22.68		20.21			2.47			12	%
Accretion of discount on asset retirement obligations	0.15		0.17			(0.02		)	-12	%
Total operating	62.25		59.01			3.24			5	%
Interest	8.42		3.69			4.73			128	%
Income tax provision (benefit)	1.62		(0.11		)	1.73			-1573	%
Total expenses	$	72.29	$	62.59		$	9.70		15	%

(a)   Includes non-cash equity-based compensation of $187,000 ($0.16 per BOE) and $(2,000) ($0.00 per BOE) for the three months ended September 30, 2013 and 2012, respectively.

Production expenses.  Production expenses attributable to LOE increased 22% to $8.8 million in the third quarter of 2013 from $7.2 million in the third quarter of 2012 as a result of an increase in production volumes from wells drilled, which contributed $5.0 million of additional LOE, partially offset by a $2.86 decrease in the average per BOE rate, which would have reduced LOE by $3.4 million if production had been unchanged.  The decrease in our average LOE per BOE rate was attributable to wells we successfully drilled and completed in 2013 where we are experiencing economies of scale from our drilling program and from savings achieved through 2012 infrastructure projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of saltwater.

Production expenses attributable to production, severance, and ad valorem taxes increased 94% to $5.4 million in the third quarter of 2013 from $2.8 million in the third quarter of 2012 primarily due to higher wellhead revenues resulting from increased production from our drilling activity.  As a percentage of wellhead revenues, production, severance, and ad valorem taxes decreased to 6.2% in the third quarter of 2013 as compared to 6.7% in the third quarter of 2012 primarily due to an increase in the number of wells brought on production in the third quarter of 2013 as compared to the third quarter of 2012 as we had additional rigs and continue to utilize more efficient drilling rigs, reducing our time from spud to rig release.

24

DD&A expense.  DD&A expense increased 56% to $23.6 million in the third quarter of 2013 from $15.1 million in the third quarter of 2012 primarily due to an increase in production volumes and an increase in our asset base subject to amortization as a result of our drilling activity.

G&A expense.  G&A expense increased 215% to $6.7 million in the third quarter of 2013 from $2.1 million in the third quarter of 2012 primarily due to (i) $1.1 million of bonuses paid subsequent to the successful completion of our IPO, (ii) $1.0 million of non-cash equity-based compensation related to the accelerated vesting of Holdings’ Class B limited partner interest as a result of the IPO, and (iii) higher payroll and payroll-related costs as we continue to add employees in order to manage our growing asset base.

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.  During the third quarter of 2013, we recorded a $27.0 million derivative fair value loss as compared to $14.3 million in the third quarter of 2012.  Since we do not use hedge accounting, changes in fair value of our derivatives are recognized as gains and losses in the current period.  Included in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums during the third quarter of 2013 of $7.1 million as compared to total cash settlements received on derivatives adjusted for recovered premiums of $0.3 million during the third quarter of 2012.

Interest expense.  Interest expense increased to $10.0 million in the third quarter of 2013 from $2.6 million in the third quarter of 2012 due to higher long-term debt balances and higher borrowing costs in the third quarter of 2013 when compared to the third quarter of 2012.  Our weighted-average total debt was $527.7 million for the third quarter of 2013 as compared to $248.0 million for the third quarter of 2012.  This increase in total debt was due to funding requirements to develop our oil and natural gas properties that are not covered by our operating cash flows.

Our weighted-average interest rate increased to 7.5% for the third quarter of 2013 as compared to 4.2% for the third quarter of 2012.  This increase in borrowing cost is primarily due to the issuance of the Notes, a portion of the net proceeds from which were used to substantially pay down outstanding borrowings on our credit agreement that were subject to lower interest rates than borrowings on the Notes.

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

	Three months ended September 30,					Increase /
	2013			2012		(Decrease)
	(in thousands)
Credit agreement	$	417		$	1,690	$	(1,273	)
Senior notes	9,147			—		9,147
Former second lien term loan	—			679		(679		)
Write off of debt issuance costs	—			57		(57		)
Amortization of debt issuance costs	545			176		369
Less: interest capitalized	(70		)	—		(70		)
Total	$	10,039		$	2,602	$	7,437

Income taxes.  In the third quarter of 2013, we recorded an income tax provision of $1.9 million as compared to an income tax benefit of $76,000 in the third quarter of 2012.  In the third quarter of 2013, we had income before income taxes and noncontrolling interest of $4.2 million as compared to a loss before income taxes and noncontrolling interest $2.2 million in the third quarter of 2012.  Our effective tax rate increased to 46.0% in the third quarter of 2013 as compared to 3.5% in the third quarter of 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.  We expect our effective tax rate to be approximately 39.8% for the fourth quarter of 2013.

25

Comparison of Nine Months Ended September 30, 2013 to Nine Months Ended September 30, 2012

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

	Nine months ended September 30,				Increase / (Decrease)
	2013		2012		$			%
Revenues (in thousands):
Oil	$	175,934	$	91,407	$	84,527		92	%
Natural gas	11,894		5,323		6,571			123	%
NGLs	20,508		14,379		6,129			43	%
Total revenues	$	208,336	$	111,109	$	97,227		88	%
Average realized prices:
Oil ($/Bbl) (excluding impact of cash settled derivatives)	$	94.43	$	90.46	$	3.97		4	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	90.19	$	88.00	$	2.19		2	%
Natural gas ($/Mcf)	$	3.42	$	2.46	$	0.96		39	%
NGLs ($/Bbl)	$	30.87	$	35.37	$	(4.50	)	-13	%
Combined ($/BOE) (excluding impact of cash settled derivatives)	$	67.07	$	62.49	$	4.58		7	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	64.52	$	61.09	$	3.43		6	%
Total production volumes:
Oil (MBbls)	1,863		1,011		852			84	%
Natural gas (MMcf)	3,474		2,165		1,309			60	%
NGLs (MBbls)	664		407		257			63	%
Combined (MBOE)	3,106		1,778		1,328			75	%
Average daily production volumes:
Oil (Bbls/D)	6,824		3,688		3,136			85	%
Natural gas (Mcf/D)	12,725		7,903		4,822			61	%
NGLs (Bbls/D)	2,433		1,484		949			64	%
Combined (BOE/D)	11,378		6,489		4,889			75	%

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

	Nine months ended September 30,
	2013			2012
Average realized oil price ($/Bbl)	$	94.43		$	90.46
Average NYMEX ($/Bbl)	$	98.17		$	96.20
Differential to NYMEX	$	(3.74	)	$	(5.74	)
Average realized oil price to NYMEX percentage	96		%	94		%
Average realized natural gas price ($/Mcf)	$	3.42		$	2.46
Average NYMEX ($/Mcf)	$	3.67		$	2.59
Differential to NYMEX	$	(0.25	)	$	(0.13	)
Average realized natural gas price to NYMEX percentage	93		%	95		%

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

Oil revenues increased 92% to $175.9 million in the first nine months of 2013 from $91.4 million in the first nine months of 2012 as a result of an increase in our oil production volumes of 852 MBbls and a $3.97 per Bbl decrease in our average realized oil price.

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Our higher oil production increased oil revenues by $77.1 million and was primarily the result of our development program in the Permian Basin.  Our higher average realized oil price increased oil revenues by $7.4 million and was primarily due to a higher average NYMEX price, which increased to $98.17 per Bbl in the first nine months of 2013 from $96.20 per Bbl in the first nine months of 2012, partially offset by the narrowing of our oil differentials as previously discussed.

Natural gas revenues increased 123% to $11.9 million in the first nine months of 2013 from $5.3 million in the first nine months of 2012 as a result of an increase in our natural gas production volumes of 1,309 MMcf and a $0.96 per Mcf increase in our average realized natural gas price.  Our higher average realized natural gas price increased natural gas revenues by $3.3 million and was primarily due to a higher average NYMEX price, which increased to $3.67 per Mcf in the first nine months of 2013 from $2.59 per Mcf in the first nine months of 2012.  Our higher natural gas production increased natural gas revenues by $2.2 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring a portion of our natural gas production as either (i) our well is not yet tied into the third-party gathering system, (ii) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported, or (iii) our production is prorated due to high demand on the third-party gathering system.  During the first nine months of 2013, we estimate that we flared approximately 3.4 MMcfe/D net, which included both residue gas and NGL production.  We expect to continue flaring until further improvements can be made to various third-party gathering systems, which are scheduled to be completed early in the fourth quarter of 2013.

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

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

	Nine months ended September 30,					Increase / (Decrease)
	2013		2012			$			%
Expenses (in thousands):
Production:
Lease operating (a)	$	23,774	$	17,846		$	5,928		33	%
Production, severance, and ad valorem taxes	13,380		7,617			5,763			76	%
Processing, gathering, and overhead	169		55			114			207	%
Total production expenses	37,323		25,518			11,805			46	%
Other:
Depletion, depreciation, and amortization	62,022		37,770			24,252			64	%
General and administrative	13,723		7,212			6,511			90	%
Contract termination fee	2,408		—			2,408			N/A
Derivative fair value loss (gain)	21,331		(9,590		)	30,921			-322	%
Accretion of discount on asset retirement obligations	485		343			142			41	%
Total operating	137,292		61,253			76,039			124	%
Interest	26,595		5,804			20,791			358	%
Income tax provision	6,805		1,546			5,259			340	%
Total expenses	$	170,692	$	68,603		$	102,089		149	%
Expenses (per BOE):
Production:
Lease operating (a)	$	7.65	$	10.04		$	(2.39	)	-24	%
Production, severance, and ad valorem taxes	4.31		4.27			0.04			1	%
Processing, gathering, and overhead	0.05		0.03			0.02			67	%
Total production expenses	12.01		14.34			(2.33		)	-16	%
Other:
Depletion, depreciation, and amortization	19.97		21.24			(1.27		)	-6	%
General and administrative	4.42		4.06			0.36			9	%
Contract termination fee	0.78		—			0.78			N/A
Derivative fair value loss (gain)	6.87		(5.39		)	12.26			-227	%
Accretion of discount on asset retirement obligations	0.16		0.19			(0.03		)	-16	%
Total operating	44.21		34.44			9.77			28	%
Interest	8.56		3.26			5.30			163	%
Income tax provision	2.19		0.87			1.32			152	%
Total expenses	$	54.96	$	38.57		$	16.39		42	%

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

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

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

DD&A expense.  DD&A expense increased 64% to $62.0 million in the first nine months of 2013 from $37.8 million in the first nine months of 2012 primarily due to an increase in production volumes and an increase in our asset base subject to amortization as a result of our drilling activity.

28

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

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

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

Our weighted-average interest rate increased to 7.3% for the first nine months of 2013 as compared to 3.7% for the first nine months of 2012.  This increase in borrowing cost is primarily due to the issuance of the Notes, a portion of the net proceeds from which were used to substantially pay down outstanding borrowings on our credit agreement that were subject to lower interest rates than borrowings on the Notes.  Our weighted-average interest expense for the first nine months of 2013 includes the impact of the write off of unamortized debt issuance costs and is expected to decline in future periods as we are not anticipating a need for a similar write off and as borrowings on the credit agreement increase relative to the Notes resulting in a lower average interest rate.

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

	Nine months ended September 30,					Increase /
	2013			2012		(Decrease)
	(in thousands)
Credit agreement	$	3,027		$	4,613	$	(1,586	)
Senior notes	16,854			—		16,854
Former second lien term loan	2,777			679		2,098
Write off of debt issuance costs	2,838			57		2,781
Amortization of debt issuance costs	1,280			455		825
Less: interest capitalized	(181		)	—		(181		)
Total	$	26,595		$	5,804	$	20,791

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

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Capital Commitments, Capital Resources, and Liquidity

Capital commitments

Our primary uses of cash are:

·Development and exploration of oil and natural gas properties;

·Acquisitions of oil and natural gas properties;

·Funding of working capital; and

·Contractual obligations.

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

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(in thousands)
Development (a)	$	42,430	$	37,173	$	132,883	$	97,884
Exploration (b)	65,402		33,666		145,435		90,892
Total	$	107,832	$	70,839	$	278,318	$	188,776

(a)Includes asset retirement obligations incurred of $200,000 and $154,000 during the three months ended September 30, 2013 and 2012, respectively, and $426,000 and $317,000 during the nine months ended September 30, 2013 and 2012, respectively.

(b)Includes asset retirement obligations incurred of $117,000 and $76,000 during the three months ended September 30, 2013 and 2012, respectively, and $311,000 and $237,000 during the nine months ended September 30, 2013 and 2012, respectively.

Our development capital primarily relates to the drilling of development and infill wells, workovers of existing wells, and the construction of field related facilities.  Our development capital for the third quarter of 2013 yielded 18 gross (18 net) productive wells and no dry holes.  Our development capital for the first nine months of 2013 yielded 51 gross (50 net) productive 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 third quarter of 2013 yielded 28 gross (27 net) productive wells and no dry holes.  Our exploration capital for the first nine months of 2013 yielded 74 gross (70 net) productive wells and no dry holes.

Our development and exploration activities in the third quarter and first nine months of 2013 were higher than in the comparable periods of 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 2013, we expect our drilling capital expenditures to be between $380 million to $390 million, plus an additional $15 million for leasing, infrastructure, and capital workovers, and drill 169 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells.

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

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(in thousands)
Acquisitions of proved properties (a)	$	3,113	$	223	$	5,883	$	3,126
Acquisitions of unproved proerpties	17,009		302		30,985		532
Total	$	20,122	$	525	$	36,868	$	3,658

(a)Includes asset retirement obligations incurred of $70,000 and $335,000 during the three and nine months ended September 30, 2013, respectively.

30

Funding of working capital.  As of September 30, 2013 and December 31, 2012, our working capital (defined as total current assets less total current liabilities) was a $108.6 million surplus and a $22.2 million deficit, respectively.  Since our principal source of operating cash flows comes from oil and natural gas reserves to be produced in future periods, which cannot be reported as working capital, we often have negative working capital.  For the remainder of 2013, we expect to continue to have a working capital surplus unless significant acquisition opportunities present themselves.  We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs, capital expenditures, and other obligations for at least the next 12 months.  We expect that our production volumes, commodity prices, and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

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

	Payments Due by Period
Contractual Obligations and Commitments	Total		Three Months Ending December 31, 2013		Years Ending December 31, 2014 - 2015		Years Ending December 31, 2016 - 2017		Thereafter
	(in thousands)
Credit agreement (a)	$	—	$	—	$	—	$	—	$	—
Senior notes (a)	795,000		18,437		73,750		73,750		629,063
Commodity derivative contracts (b)	9,966		4,536		5,430		—		—
Development commitments (c)	60,092		60,092		—		—		—
Operating leases and commitments (d)	1,433		117		938		378		—
Asset retirement obligations (e)	39,275		60		—		—		39,215
Total	$	905,766	$	83,242	$	80,118	$	74,128	$	668,278

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

(b)Represents net liabilities for our commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk.  Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information regarding our commodity derivative contracts.

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

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

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

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

Capital resources

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

	Nine months ended September 30,						Increase /
	2013			2012			(Decrease)
	(in thousands)
Net cash provided by operating activities	$	136,775		$	62,754		$	74,021
Net cash used in investing activities	(295,003		)	(186,900		)	(108,103		)
Net cash provided by financing activities	346,245			100,850			245,395
Net increase (decrease) in cash	$	188,017		$	(23,296	)	$	211,313

Cash flows from operating activities.  Cash provided by operating activities increased $74.0 million to $136.8 million in the first nine months of 2013 from $62.8 million in the first nine months of 2012, primarily due to an increase in our production margin due to a 75% increase in our total production volumes as a result of wells drilled, partially offset by increased expenses as a result of having more producing wells in the first nine months of 2013 as compared to the first nine months of 2012.

31

Cash flows used in investing activities.  Cash used in investing activities increased $108.1 million to $295.0 million in the first nine months of 2013 from $186.9 million in the first nine months of 2012, primarily due to a $74.7 million increase in amounts paid to develop oil and natural gas properties and a $33.2 million increase in leasehold acquisition costs.  The increase in our development expenditures was primarily due to (i) our utilization of more efficient vertical drilling rigs that have significantly reduced the time from spud to rig release allowing, us to drill and complete more wells over the same time period, and (ii) our higher rig count, including our first horizontal drilling rig which was added in the third quarter of 2013.

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

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

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

Liquidity

Our primary sources of liquidity historically have been internally generated cash flows, the borrowing capacity under our credit agreement, and partner contributions, including partner contributions from our equity sponsor, the Apollo Funds.  Since we operate a majority of our wells, we have the ability to adjust our capital expenditures as economic conditions change.  We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.  We believe that our internally generated cash flows and expected future availability under our credit agreement 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 2013, we expect our drilling capital expenditures to be between $380 million to $390 million, plus an additional $15 million for leasing, infrastructure, and capital workovers.  The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions.  We plan to finance our ongoing expenditures using internally generated cash flow and availability under our credit agreement.

Internally generated cash flows.  Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil, natural gas, and NGL prices.  During the first nine months of 2013, our average realized oil and natural prices increased by 4% and 39%, respectively, as compared to the first nine months of 2012, while our average realized NGL price decreased by 13%.  Realized commodity prices fluctuate widely in response to changing market forces.  If commodity prices decline or we experience a significant widening of our differentials to NYMEX prices, then our results of operations, cash flows from operations, and borrowing base under our credit agreement may be adversely impacted.  Prolonged periods of lower commodity prices or sustained wider differentials to NYMEX prices could cause us to not be in compliance with financial covenants under our credit agreement and thereby affect our liquidity.  To offset reduced cash flows in a lower commodity price environment, we have established a portfolio of commodity derivative contracts consisting primarily of oil swaps that will provide stable cash flows on a portion of our oil production.  As of September 30, 2013, our hedged oil volumes for the fourth quarter of 2013, 2014, and 2015 represent 89%, 101%, and 16%, respectively, of our third quarter of 2013 oil production at weighted average prices of $95.01 per Bbl, $92.67 per Bbl, and $93.18 per Bbl, respectively.  An increase in oil prices above the ceiling prices in our commodity derivative contracts limits cash inflows because we would be required to pay our counterparties for the difference between the market price for oil and the ceiling price of the commodity derivative contract resulting in a loss.  Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our commodity derivative contracts.

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

In conjunction with the offering of our senior notes in April 2013 as discussed below, the borrowing base under our credit agreement was reduced to $267.5 million.  We used a portion of the net proceeds from the offering of the senior notes and our IPO to reduce the outstanding borrowings under our credit agreement.   In May 2013, we amended our credit agreement to, among other things, increase the borrowing base to $320 million.  As of September 30, 2013, the borrowing base was $320 million and there were no outstanding borrowings and no outstanding letters of credit under our credit agreement. In November 2013, we amended our credit agreement to, among other things, increase the borrowing base to $525 million. As of November 14, 2013, there were no outstanding borrowings under our credit agreement.

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

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

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

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

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

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

·a prohibition against incurring debt, subject to permitted exceptions;

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

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

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

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

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

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

Certain of the lenders underwriting our credit agreement are also counterparties to our commodity derivative contracts. Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion.

Senior notes.  In April 2013, we issued $500 million aggregate principal amount of 7 3/8% senior notes due 2021.  The net proceeds from the senior notes offering were used to repay a portion of the outstanding borrowings under our credit agreement, to repay in full and terminate our former second lien term loan, to make a $75 million distribution to Holdings Class A limited partners, and for general partnership purposes.  On August 14, 2013, Holdings entered into a supplemental indenture pursuant to which we became an unconditional guarantor of the Notes.

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

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

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

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

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

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

Capitalization.  At September 30, 2013, we had total assets of $1.3 billion and total capitalization of $1.1 billion, of which 55% was represented by equity and 45% by long-term debt.  At December 31, 2012, we had total assets of $852.3 million and total capitalization of $782.9 million, of which 54% was represented by equity and 46% by long-term debt.  The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

On August 7, 2013, we completed our IPO of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $295.6 million, after deducting underwriting discounts and commissions and offering expenses.  We used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of our purchase of New Holdings Units (i) to reduce outstanding borrowings under our credit agreement, (ii) to provide additional liquidity for use in our drilling program, and (iii) for general corporate purposes, including potential acquisitions.

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Changes in Prices

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

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Average realized prices:
Oil ($/Bbl) (excluding impact of cash settled derivatives)	$	104.21	$	88.28	$	94.43	$	90.46
Oil ($/Bbl) (after impact of cash settled derivatives)	94.39		89.03		90.19		88.00
Natural gas ($/Mcf)	3.28		2.66		3.42		2.46
NGLs ($/Bbl)	33.76		31.90		30.87		35.37
Combined ($/BOE) (excluding impact of cash settled derivatives)	74.16		59.62		67.07		62.49
Combined ($/BOE) (after impact of cash settled derivatives)	68.18		60.03		64.52		61.09

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

Critical Accounting Policies and Estimates

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our final prospectus dated August 1, 2013 and filed with the SEC on August 5, 2013.

Income Taxes

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

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

In April 2013, we had a corporate reorganization to effectuate our IPO.  Holdings, our accounting predecessor, is a partnership structure not subject to federal income tax.  Pursuant to the steps of 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.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

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

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Derivative policy

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

Counterparties

At September 30, 2013, we had committed 10% or greater (in terms of fair market value) of our oil derivative contracts in asset positions to the following counterparties, or one of their affiliates:

	Fair Market Value of
	Oil Derivative
	Contracts
Counterparty	Committed
	(in thousands)
BNP Paribas	$	458

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

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

Commodity price sensitivity

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

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

	Average	Weighted -		Average	Weighted -		Average	Weighted -		Asset
	Daily	Average		Daily	Average		Daily	Average		(Liability)
	Floor	Floor		Cap	Cap		Swap	Swap		Fair Market
Period	Volume	Price		Volume	Price		Volume	Price		Value
	(Bbl)	(per Bbl)		(Bbl)	(per Bbl)		(Bbl)	(per Bbl)		(in thousands)
Oct. - Dec. 2013	150	$	75.00	150	$	105.95	7,000	$	95.01	$	(4,205	)
2014	—	—		—	—		7,950	92.67		(7,532		)
2015	—	—		—	—		1,300	93.18		2,101
										$	(9,636	)

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

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

Interest rate sensitivity

At September 30, 2013, we had outstanding debt of $500 million, all of which bears interest at a fixed rate of 7 3/8%.  At September 30, 2013, the fair value of our senior notes was approximately $515.6 million.

Item 4.  Controls and Procedures

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

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

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 1A.  Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Risk Factors” in our final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act on August 5, 2013, which could materially affect our business, financial condition, and/or future results.  The risks described in our final prospectus are not the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

Item 5.  Other Information

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

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

Apollo has informed us that CEVA has provided it with the information below relevant to Section 13(r) of the Exchange Act.  The disclosure below does not relate to any activities conducted by us and does not involve us or our management.  The disclosure relates solely to activities conducted by 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 December 2012, CEVA Freight Italy Srl (“CEVA Italy”) provided customs brokerage and freight forwarding services for the export to Iran of two measurement instruments to the Iranian Offshore Engineering Construction Company, a joint venture between two entities that are identified on OFAC’s list of Specially Designated Nationals (“SDN”).  The revenues and net profits for these services were approximately $1,260.64 USD and $151.30 USD, respectively.  In February 2013, CEVA Freight Holdings (Malaysia) SDN BHD (“CEVA Malaysia”) provided customs brokerage for export and local haulage services for a shipment of polyethylene resin to Iran shipped on a vessel owned and/or operated by HDS Lines, also an SDN.  The revenues and net profits for these services were approximately $779.54 USD and $311.13 USD, respectively.  In September 2013, CEVA Malaysia provided customs brokerage services for the import into Malaysia of fruit juice from Alifard Co. in Iran via HDS Lines.  The revenues and net profits for these services were approximately $227.41 USD and $89.29 USD, respectively.

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

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Item 6.  Exhibits

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of Athlon Energy Inc. (incorporated by reference from 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 from 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	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 7 3/8% 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).
10.1+	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).
10.2+	Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and William B. D. Butler (incorporated by reference to Exhibit 10.1 to Athlon’s Current Report on Form 8-K, filed with the SEC on August 15, 2013).
10.3+	Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and Nelson K. Treadway (incorporated by reference to Exhibit 10.1 to Athlon’s Current Report on Form 8-K, filed with the SEC on August 15, 2013).
10.4+	Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and David B. McClelland (incorporated by reference to Exhibit 10.1 to Athlon’s Current Report on Form 8-K, filed with the SEC on August 15, 2013).
10.5+	Athlon Energy Inc. 2013 Incentive Stock Plan (incorporated by reference from Exhibit 4.3 to Athlon’s Registration Statement on Form S-8 (File No. 333-190734), filed with the SEC on August 20, 2013).
10.6*+	Form of Restricted Stock Unit Grant Notice—Executive.
10.7*	Tax Receivable Agreement by and among Athlon Energy Inc., Athlon Holdings LP, and each of the Partners named therein.
10.8*	Exchange Agreement by and among Athlon Energy Inc. and each of the Partners named therein.
10.9*	Stockholders Agreement by and among Athlon Energy Inc. and those stockholders named therein.
10.10*	Advisory Services and Transaction Fee Termination Agreement by and among Athlon Holdings LP, Apollo Management VII, L.P. and Apollo Global Securities, LLC.
10.11*	Amended and Restated Agreement of Limited Partnership of Athlon Holdings LP.
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).
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

*Filed herewith.

+Management contract or compensatory plan, contract, or arrangement.

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SIGNATURES

Pursuant to the requirements 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.

	ATHLON ENERGY INC.
	/s/ William B. D. Butler
	William B. D. Butler
	Vice President—Chief Financial Officer and
	Principal Financial Officer
	/s/ John C. Souders
	John C. Souders
	Vice President—Controller and
	Principal Accounting Officer
Date: November 14, 2013

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