Athlon Energy Inc. - FORM 10-Q

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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, 2014

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

Number of shares of common stock, $0.01 par value, outstanding as of November 12, 2014 98,459,476

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ATHLON ENERGY INC.

INDEX

		Page
	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	1

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013	2

	Consolidated Statement of Changes in Equity for the Nine Months Ended September 30, 2014	3

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013	4

	Notes to Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34

Item 4.	Controls and Procedures	36

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	37

Item 1A.	Risk Factors	37

Item 6.	Exhibits	37

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 “Item 1A. Risk Factors” and elsewhere in our 2013 Annual Report on Form 10-K and in our other filings with the SEC. 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.

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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.

· 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.

· 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.

· 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.

· Mcf/d. One thousand cubic feet of natural gas per day.

· MMcf. One million cubic feet of natural gas.

· 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.

· NYMEX. The New York Mercantile Exchange.

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

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

· 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

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complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

· 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).

· 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.

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

· 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

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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,
	2014			2013
	(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	4,997		$	113,025
Accounts receivable	97,162			48,238
Derivatives, at fair value	16,948			—
Inventory	1,910			928
Deferred taxes	—			380
Other	2,248			1,166
Total current assets	123,265			163,737

Properties and equipment, at cost - full cost method:
Evaluated, including wells and related equipment	2,525,499			1,244,178
Unevaluated	678,879			89,859
Accumulated depletion, depreciation, and amortization	(277,347		)	(160,779		)
	2,927,031			1,173,258

Derivatives, at fair value	9,327			2,330
Debt issuance costs	25,101			14,679
Other	2,393			1,447
Total assets	$	3,087,117		$	1,355,451

LIABILITIES AND EQUITY

Current liabilities:
Trade accounts payable	$	220		$	459
Accrued liabilities:
Lease operating	10,631			6,563
Production, severance, and ad valorem taxes	10,462			2,550
Development capital	118,105			68,059
Interest	33,337			7,790
Derivatives, at fair value	—			8,354
Revenue payable	35,233			20,513
Deferred taxes	4,450			—
Other	6,573			4,035
Total current liabilities	219,011			118,323

Asset retirement obligations, net of current portion	12,328			6,795
Long-term debt	1,386,000			500,000
Deferred taxes	141,070			92,397
Other	152			101
Total liabilities	1,758,561			717,616

Commitments and contingencies

Equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized, none issued and outstanding	—			—
Common stock, $0.01 par value, 500,000,000 shares authorized 97,134,446 and 82,129,089 issued and outstanding, respectively	971			821
Additional paid-in capital	1,182,006			593,943
Retained earnings	131,644			32,283
Total stockholders’ equity	1,314,621			627,047
Noncontrolling interest	13,935			10,788
Total equity	1,328,556			637,835
Total liabilities and equity	$	3,087,117		$	1,355,451

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

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ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Revenues:
Oil	$	139,925		$	75,666		$	341,144		$	175,934
Natural gas	9,795			4,164			25,907			11,894
Natural gas liquids	16,321			8,595			41,169			20,508
Total revenues	166,041			88,425			408,220			208,336

Expenses:
Production:
Lease operating	16,677			8,762			42,126			23,774
Production, severance, and ad valorem taxes	11,647			5,498			27,060			13,549
Depletion, depreciation, and amortization	50,246			23,611			116,792			62,022
General and administrative	15,310			6,696			38,718			13,543
Contract termination fee	—			2,408			—			2,408
Acquisition costs	388			29			2,213			180
Derivative fair value loss (gain)	(58,526		)	27,037			(14,949		)	21,331
Accretion of discount on asset retirement obligations	273			174			690			485
Total expenses	36,015			74,215			212,650			137,292

Operating income	130,026			14,210			195,570			71,044

Other income (expenses):
Interest	(12,502		)	(10,039		)	(35,208		)	(26,595		)
Other	36			30			62			30
Total other expenses	(12,466		)	(10,009		)	(35,146		)	(26,565		)

Income before income taxes	117,560			4,201			160,424			44,479
Income tax provision	42,662			1,934			57,916			6,805

Consolidated net income	74,898			2,267			102,508			37,674
Less: net income (loss) attributable to noncontrolling interest	2,205			(215		)	3,147			616
Net income attributable to stockholders	$	72,693		$	2,482		$	99,361		$	37,058

Net income per common share:
Basic	$	0.74		$	0.03		$	1.08		$	0.53
Diluted	$	0.74		$	0.03		$	1.08		$	0.53

Weighted average common shares outstanding:
Basic	97,064			76,637			90,904			69,810
Diluted	97,064			78,493			90,904			71,666

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

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ATHLON ENERGY INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)

	Athlon Stockholders
	Issued
	Shares of			Additional					Total
	Common	Common		Paid-in			Retained		Stockholders’			Noncontrolling		Total
	Stock	Stock		Capital			Earnings		Equity			Interest		Equity
Balance at December 31, 2013	82,129	$	821	$	593,943		$	32,283	$	627,047		$	10,788	$	637,835
Equity-based compensation	—	—		17,726			—		17,726			—		17,726
Vesting of stock awards	199	2		(3,820		)	—		(3,818		)	—		(3,818		)
Proceeds from issuance of common stock to the public, net of offering costs	14,806	148		570,612			—		570,760			—		570,760
Deferred tax impact of change in noncontrolling interest due to issuance of common stock to the public	—	—		3,545			—		3,545			—		3,545
Consolidated net income	—	—		—			99,361		99,361			3,147		102,508
Balance at Septembder 30, 2014	97,134	$	971	$	1,182,006		$	131,644	$	1,314,621		$	13,935	$	1,328,556

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

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ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine months ended September 30,
	2014			2013
Cash flows from operating activities:
Consolidated net income	$	102,508		$	37,674
Adjustments to reconcile consolidated net income to net cash provided by operating activities:
Depletion, depreciation, and amortization	116,792			62,022
Deferred taxes	57,047			6,805
Non-cash derivative loss (gain)	(32,300		)	13,955
Equity-based compensation	16,006			1,799
Other	3,308			4,756
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(46,897		)	(21,350		)
Other current assets	562			(155		)
Accounts payable	(239		)	(702		)
Accrued interest	25,546			15,968
Revenue payable	14,709			9,718
Other current liabilities	12,717			6,285
Other assets	(90		)	—
Net cash provided by operating activities	269,669			136,775

Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(1,365,205		)	(36,533		)
Development of oil and natural gas properties	(451,360		)	(257,984		)
Other	(1,317		)	(486		)
Net cash used in investing activities	(1,817,882		)	(295,003		)

Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs	1,056,243			629,627
Payments on long-term debt	(183,000		)	(505,926		)
Proceeds from issuance of common stock to the public, net of offering costs	570,760			296,044
Distributions to Athlon Holdings LP’s Class A limited partners	—			(75,000		)
Vesting of stock awards	(3,818		)	—
Other	—			1,500
Net cash provided by financing activities	1,440,185			346,245

Increase (decrease) in cash and cash equivalents	(108,028		)	188,017
Cash and cash equivalents, beginning of period	113,025			8,871
Cash and cash equivalents, end of period	$	4,997		$	196,888

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

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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 Holdings’ business and affairs and consolidates its financial results.

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

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

Initial Public Offering

On August 7, 2013, Athlon completed its initial public offering (“IPO”) of 15,789,474 shares of its common stock at $20.00 per share and received net proceeds of approximately $295.7 million, after deducting underwriting discounts and commissions and offering expenses. Upon closing of the IPO, Holdings’ limited partnership agreement was amended and restated to, among other things, modify Holdings’ capital structure by replacing its different classes of interests with a single new class of units, the “New Holdings Units”. Holdings’ management team and certain employees that held Class A limited partner interests now own 1,855,563 New Holdings Units and entered into an exchange agreement under which (subject to the terms of the exchange agreement) they have the right to exchange their New Holdings Units for shares of Athlon’s common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications. Please read “Note 13. Related Party Transactions” for additional discussion. All other New Holdings Units are held by Athlon.

Merger with Encana

On September 27, 2014, Athlon entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Encana Corporation (“Encana”) and Alenco Acquisition Company Inc., Encana’s indirect, wholly owned subsidiary (“Alenco”), pursuant to which Alenco will merge with and into Athlon, with Athlon surviving as an indirect, wholly owned subsidiary of Encana (the “Merger”). The Merger Agreement, which was unanimously approved by Athlon’s Board of Directors and by Encana’s Board of Directors, provides for Encana’s acquisition of all of the issued and outstanding shares of Athlon’s common stock, par value $0.01 per share, for $58.50 per share in cash (the “Offer”). Completion of the Merger is conditioned upon, among other things, customary closing conditions.

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, 2014, results of operations for the three and nine months ended September 30, 2014 and 2013, and cash flows for the nine months ended September 30, 2014 and 2013. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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. Therefore, these unaudited consolidated financial statements should be read in conjunction with Athlon’s audited consolidated financial statements and related notes thereto included in Athlon’s 2013 Annual Report on Form 10-K.

Noncontrolling Interest

As of September 30, 2014 and December 31, 2013, Athlon’s management team and certain employees owned approximately 1.9% and 2.2% of Holdings, respectively. Holdings’ general partner, Athlon Holdings GP LLC, is a wholly owned subsidiary of Athlon. 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, 2014 and December 31, 2013 of approximately $13.9 million and $10.8 million, respectively, represents Athlon’s management team and certain employees’ ownership of Holdings. As presented in the accompanying Consolidated Statements of Operations, “Net income (loss) attributable to noncontrolling interest” of approximately $2.2 million and $3.1 million for the three and nine months ended September 30, 2014, respectively, and approximately $(0.2) million and $0.6 million for the three and nine months ended September 30, 2013, respectively, represents Holdings’ net income attributable to Athlon’s management team and certain employees.

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				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
	(in thousands)
Net income attributable to stockholders	$	72,693	$	2,482	$	99,361	$	37,058
Transfer from noncontrolling interest:
Increase in Athlon’s paid-in capital for deferred tax impact of change in noncontrolling interest due to issuance of common stock to the public	4,155		—		3,545		—
Increase in Athlon’s paid-in capital for corporate reorganization	—		—		—		290,950
Increase in Athlon’s paid-in capital for issuance of common stock to the public	63		295,473		570,612		295,473
Net transfer from noncontrolling interest	4,218		295,473		574,157		586,423
Change from net income attributable to stockholders and transfers from noncontrolling interest	$	76,911	$	297,955	$	673,518	$	623,481

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers”. ASU 2014-09 supersedes most of the existing revenue recognition requirements in accounting principles generally accepted in the United States (“GAAP”) and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. ASU 2014-09 is effective retrospectively for annual and interim reporting periods beginning after December 15, 2016, with early application not permitted. Athlon is evaluating the impact, if any, that the adoption of ASU 2014-09 will have on its financial position, results of operations, and liquidity.

No other new accounting pronouncements issued or effective from January 1, 2014 through the date of this Report, had or are expected to have a material impact on Athlon’s unaudited consolidated financial statements.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Note 3. Acquisitions

On June 2, 2014, Athlon acquired certain oil and natural gas properties and related assets in the Midland Basin from Hibernia Holdings, LLC (“Hibernia”) for approximately $394.0 million in cash, which was financed with a portion of the net proceeds from debt and equity offerings. Please read “Note 7. Long-Term Debt” and “Note 8. Stockholders’ Equity” for additional discussion of these offerings. The operations of these properties have been included in the accompanying Consolidated Statements of Operations with those of Athlon from the date of acquisition. Athlon has included revenues of $30.3 million and direct operating expenses of $3.5 million for the period June 2, 2014 to September 30, 2014 due to the Hibernia acquisition in the accompanying Consolidated Statements of Operations. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. Athlon incurred approximately $0.7 million of transaction costs related to the Hibernia acquisition, which are included in “Acquisition costs” in the accompanying Consolidated Statements of Operations.

On June 3, 2014, Athlon acquired certain oil and natural gas properties and related assets in the Midland Basin from Piedra Energy II, LLC (“Piedra”) for approximately $292.8 million in cash, which was financed with a portion of the net proceeds from debt and equity offerings. Please read “Note 7. Long-Term Debt” and “Note 8. Stockholders’ Equity” for additional discussion of these offerings. The operations of these properties have been included in the accompanying Consolidated Statements of Operations with those of Athlon from the date of acquisition. Athlon has included revenues of $12.4 million and direct operating expenses of $1.8 million for the period June 3, 2014 to September 30, 2014 due to the Piedra acquisition in the accompanying Consolidated Statements of Operations. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. Athlon incurred approximately $0.6 million of transaction costs related to the Piedra acquisition, which are included in “Acquisition costs” in the accompanying Consolidated Statements of Operations.

On August 28, 2014, Athlon acquired certain oil and natural gas properties and related assets in the Midland Basin from Summit West Resources LP and Summit Group (“Summit”) for approximately $202.5 million in cash, which was financed with cash on hand and borrowings under Athlon’s credit agreement. The operations of these properties have been included in the accompanying Consolidated Statements of Operations with those of Athlon from the date of acquisition. Athlon has included revenues of $2.4 million and direct operating expenses of $0.5 million for the period August 28, 2014 to September 30, 2014 due to the Summit acquisition in the accompanying Consolidated Statements of Operations. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. Athlon incurred approximately $0.1 million of transaction costs related to the Summit acquisition, which are included in “Acquisition costs” in the accompanying Consolidated Statements of Operations.

Based on currently available information, the estimated allocation of the purchase price to the fair value of the assets acquired and liabilities assumed from Hibernia, Piedra, and Summit was as follows as of September 30, 2014:

	Hibernia		Piedra		Summit		Total
	(in thousands)
Evaluated, including wells and related equipment	$	248,363	$	173,317	$	93,899	$	515,579
Unevaluated	145,984		119,504		109,570		375,058
Inventory	499		759		132		1,390
Total assets acquired	394,846		293,580		203,601		892,027
Other current liabilities	107		289		659		1,055
Asset retirement obligations	706		536		437		1,679
Total liabilities assumed	813		825		1,096		2,734
Fair value of net assets acquired	$	394,033	$	292,755	$	202,505	$	889,293

At September 30, 2014, Athlon was awaiting final close on the Hibernia and Summit acquisitions, which will contain certain customary purchase price adjustments.

The following unaudited pro forma condensed financial data was derived from the historical financial statements of Athlon and from the accounting records of Hibernia, Piedra, and Summit to give effect to the acquisitions as if they had occurred on January 1, 2013. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the acquisitions taken place on January 1, 2013 and is not intended to be a projection of future results.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
	(in thousands, except per share amounts)
Pro forma total revenues	$	171,740	$	116,169	$	471,830	$	271,420
Pro forma net income attributable to stockholders	$	75,259	$	4,398	$	111,592	$	38,197

Pro forma net income per common share:
Basic	$	0.76	$	0.05	$	1.14	$	0.45
Diluted	$	0.76	$	0.05	$	1.14	$	0.45

Note 4. Evaluated Properties

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

	September 30,		December 31,
	2014		2013
	(in thousands)
Evaluated leasehold costs	$	1,156,611	$	448,689
Wells and related equipment - completed	1,314,766		748,900
Wells and related equipment - in process	54,122		46,589
Total evaluated	$	2,525,499	$	1,244,178

Note 5. 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, 2014, the fair value of Athlon’s 73/8% senior notes due 2021 was approximately $542.5 million and the fair value of Athlon’s 6% senior notes due 2022 was approximately $698.8 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 under Athlon’s 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.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Commodity Derivative Contracts

Commodity prices are often subject to significant volatility due to many factors that are beyond Athlon’s control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. Athlon manages oil price risk with swaps, which provide a fixed price for a notional amount of sales volumes. The following table summarizes Athlon’s open commodity derivative contracts as of September 30, 2014:

Period	Average Daily Swap Volume	Weighted- Average Swap Price		Net Asset Fair Market Value
	(Bbl)	(per Bbl)		(in thousands)
Q4 2014	10,961	$	92.31	$	2,168

Q1 2015	12,800	92.12
Q2 2015	12,800	92.12
Q3 2015	11,800	93.69
Q4 2015	11,800	93.69
2015	12,296	92.88		22,727

Q1 2016	2,500	92.35
Q2 2016	2,500	92.35
2016	1,243	92.35		2,718
				$	27,613

Athlon is also a party to Midland-Cushing basis differential swaps for 6,000 Bbls/D at $5.19/Bbl for 2015. At September 30, 2014, the fair value of these contracts was a net liability of approximately $1.3 million.

Counterparty Risk. At September 30, 2014, Athlon had committed 10% or greater (in terms of fair market value) of its oil derivative contracts in asset positions from the following counterparties:

	Fair Market Value of
	Oil Derivative
	Contracts
Counterparty	Committed
	(in thousands)
Citibank	$	7,524
Barclays PLC	6,187
Scotiabank	4,953
J Aron	4,397

Athlon does not require collateral from its counterparties for entering into derivative instruments, so in order to mitigate the credit risk associated with such derivative instruments, Athlon enters into an International Swap Dealers Association Master Agreement (“ISDA Agreement”) with each of its counterparties. The ISDA Agreement is a standardized, bilateral contract between a given counterparty and Athlon. Instead of treating each derivative transaction between the counterparty and Athlon separately, the termination provision of the ISDA Agreement enables the counterparty and Athlon to aggregate all trades under such agreement 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 trade can trigger rights to terminate all trades with such counterparty that are subject to the ISDA Agreement; and (ii) netting of settlement amounts reduces Athlon’s credit exposure to a given counterparty in the event of close-out. Athlon’s accounting policy is to not offset fair value amounts between different counterparties for derivative instruments in the accompanying Consolidated Balance Sheets.

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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, 2014
Assets
Derivatives - current	$	17,751		$	(803	)	$	16,948
Derivatives - noncurrent	9,940			(613		)	9,327
Total assets	27,691			(1,416		)	26,275
Liabilities
Derivatives - current	(803		)	803			—
Derivatives - noncurrent	(613		)	613			—
Total liabilities	(1,416		)	1,416			—
Net asset	$	26,275		$	—		$	26,275

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

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

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

		Amount of Loss (Gain) Recognized in Income
	Location of Loss (Gain)	Three months ended September 30,					Nine months ended September 30,
Derivatives Not Designated as Hedges	Recognized in Income	2014			2013		2014			2013
		(in thousands)
Commodity derivative contracts	Derivative fair value loss (gain)	$	(58,526	)	$	27,037	$	(14,949	)	$	21,331

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. 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.

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

Athlon adjusts the valuations from the valuation model for nonperformance risk. For commodity derivative contracts which are in an asset position, Athlon adds the counterparty’s credit default swap spread to the risk-free rate. If a counterparty does not have a credit default swap spread, Athlon uses other companies with similar credit ratings to determine the applicable spread. For commodity derivative contracts which are in a liability position, Athlon uses the yield on its senior notes less the risk-free rate. All fair values have been adjusted for nonperformance risk resulting in a decrease in the net commodity derivative asset of approximately $56,000 as of September 30, 2014 and a decrease in the net commodity derivative liability of approximately $39,000 as of December 31, 2013.

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	Net Asset/(Liability)			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
As of September 30, 2014
Oil derivative contracts - swaps	$	27,613		$	—	$	27,613		$	—
Oil derivative contracts - basis differential swaps	(1,338		)	—		(1,338		)	—
Total	$	26,275		$	—	$	26,275		$	—

As of December 31, 2013
Oil derivative contracts - swaps	$	(6,024	)	$	—	$	(6,024	)	$	—

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Note 6. 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, 2014 (in thousands):

Balance at January 1	$	6,855
Liabilities assumed in acquisitions	3,140
Liabilities incurred from new wells	1,463
Liabilities settled	(103		)
Accretion of discount	690
Revisions of previous estimates	292
Balance at September 30	12,337
Less: current portion	9
Asset retirement obligations - long-term	$	12,328

Note 7. Long-Term Debt

Long-term debt consisted of the following as of the dates indicated:

	Maturity	September 30,		December 31,
	Date	2014		2013
		(in thousands)
Credit agreement	3/19/2018	$	236,000	$	—
73/8% senior notes	4/15/2021	500,000		500,000
6% senior notes	5/1/2022	650,000		—
Total		$	1,386,000	$	500,000

Senior Notes

In April 2013, Holdings issued $500 million aggregate principal amount of 73/8% senior unsecured notes due 2021 (the “2021 Notes”). Athlon is an unconditional guarantor of the 2021 Notes. Under the indenture, starting on April 15, 2016, Athlon will be able to redeem some or all of the 2021 Notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption. Prior to April 15, 2016, Athlon will be able, at its option, to redeem up to 35% of the aggregate principal amount of the 2021 Notes at a price of 107.375% of the principal thereof, plus accrued and unpaid interest to the date of redemption, with an amount equal to the net proceeds from certain equity offerings. In addition, at Athlon’s option, prior to April 15, 2016, Athlon may redeem some or all of the 2021 Notes at a redemption price equal to 100% of the principal amount of the 2021 Notes, plus an “applicable premium”, plus accrued and unpaid interest to the date of redemption. Certain asset dispositions or a change in control will be triggering events that may require Athlon to repurchase all or any part of a noteholder’s 2021 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 2021 Notes is payable in cash semi-annually in arrears, commencing on October 15, 2013, through maturity.

On May 1, 2014, Holdings completed a private placement of $650 million aggregate principal amount of 6% senior unsecured notes due 2022 (the “2022 Notes”) and received net proceeds of approximately $639.1 million, after deducting initial purchasers’ discounts and debt issuance costs. Athlon is an unconditional guarantor of the 2022 Notes. Under the indenture, starting on May 1, 2017, Athlon will be able to redeem some or all of the 2022 Notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption. Prior to May 1, 2017, Athlon will be able, at its option, to redeem up to 35% of the aggregate principal amount of the 2022 Notes at a price of 106% of the principal thereof, plus accrued and unpaid interest to the date of redemption, with an amount equal to the net proceeds from certain equity offerings. In addition, at Athlon’s option, prior to May 1, 2017, Athlon may redeem some or all of the 2022 Notes at a redemption price equal to 100% of the principal amount of the 2022 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, 2015, Athlon may redeem all, but not less than all, of the 2022 Notes at 110% of the principal amount thereof plus accrued and unpaid interest to, but not including, the redemption date. Certain asset dispositions or a change of control that occurs after July 15, 2015 will be triggering events that may require Athlon to repurchase all or any part of a noteholder’s 2022 Notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, up to but excluding the

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

date of repurchase. Interest on the 2022 Notes is payable in cash semi-annually in arrears, commencing on November 1, 2014, through maturity.

The indentures governing Athlon’s senior notes contain covenants, including, among other things, covenants that restrict Athlon’s ability to:

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

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

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

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

As of September 30, 2014, Athlon was in compliance with all covenants of its senior notes.

Credit Agreement

Athlon is a party to an amended and restated credit agreement dated March 19, 2013 (the “Credit Agreement”), which matures on March 19, 2018. The Credit Agreement provides for revolving credit loans to be made to Athlon from time to time and letters of credit to be issued from time to time for the account of Athlon or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the Credit Agreement is $1.0 billion. Availability under the Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. Borrowings under the Credit Agreement may be repaid from time to time without penalty. As of September 30, 2014, the borrowing base was $837.5 million and there were $236 million of outstanding borrowings, $601.5 million of borrowing capacity, and no outstanding letters of credit under the Credit Agreement.

Obligations under the Credit Agreement are secured by a first-priority security interest in substantially all of Holdings’ proved reserves.

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

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

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

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

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

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

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

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

· a requirement that Athlon maintain a ratio of consolidated total debt to EBITDAX (as defined in the Credit Agreement) of not more than 4.5 to 1.0; 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.

As of September 30, 2014, Athlon was in compliance with all covenants of the Credit Agreement.

The 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 Credit Agreement to be immediately due and payable.

Note 8. Stockholders’ Equity

On April 23, 2014, Athlon completed a public offering of 14,806,250 shares of its common stock at $40.00 per share and received net proceeds of approximately $570.8 million, after deducting underwriting discounts and commissions and offering expenses. Upon consummation of the offering, Athlon’s ownership percentage of Holdings increased, resulting in a decrease in the noncontrolling interest from approximately 2.2% to approximately 1.9%.

Note 9. Income Taxes

As a result of the corporate reorganization on April 26, 2013, Athlon (a C-corporation) obtained substantially all of Holdings’ interests, Athlon’s accounting predecessor, which is a limited partnership not subject to federal income taxes.

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

	Nine months ended
	September 30,
	2014		2013
	(in thousands)
Federal:
Current	$	869	$	—
Deferred	54,992		6,202
Total federal	55,861		6,202

State, net of federal benefit:
Deferred	2,055		603
Total state	2,055		603
Income tax provision	$	57,916	$	6,805

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

	Nine months ended September 30,
	2014			2013
	(in thousands)
Income before income taxes	$	160,424		$	44,479
Less: net income prior to corporate reorganization	—			(26,780		)
Less: net income attributable to noncontrolling interest	(3,147		)	(616		)
Income before income taxes and noncontrolling interest subsequent to corporate reorganization	$	157,277		$	17,083
Income taxes at the Federal statutory rate	$	55,047		$	5,979
State income taxes, net of federal benefit	2,055			603
Provision to return adjustment	191			59
Permanent and other	623			164
Income tax provision	$	57,916		$	6,805

As of September 30, 2014 and December 31, 2013, all of Athlon’s tax positions met the “more-likely-than-not” threshold. During the nine months ended September 30, 2014 and 2013, Athlon did not have any interest assessed by the taxing authorities or incur any penalties related to income taxes.

Note 10. Earnings Per Share

Prior to the consummation of the IPO, Athlon had 960,907 shares of outstanding common stock. In conjunction with the closing of the IPO, certain of Holdings’ Class A and Class B limited partners that exchanged their interests for shares of Athlon’s common stock were subject to an adjustment based on the 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 Holdings’ interests in April 2013 to 960,907 shares of Athlon’s common stock 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 the IPO for purposes of calculating EPS.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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

	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(in thousands, except per share amounts)
Basic EPS
Numerator:
Undistributed net income attributable to stockholders	$	72,693		$	2,482		$	99,361		$	37,058
Participation rights of unvested stock awards in undistributed earnings	(1,135		)	(6		)	(1,147		)	(6		)
Basic undistributed net income attributable to stockholders	$	71,558		$	2,476		$	98,214		$	37,052
Denominator:
Basic weighted average shares outstanding	97,064			76,637			90,904			69,810
Basic EPS attributable to stockholders	$	0.74		$	0.03		$	1.08		$	0.53

Diluted EPS
Numerator:
Undistributed net income attributable to stockholders	$	72,693		$	2,482		$	99,361		$	37,058
Participation rights of unvested stock awards in undistributed earnings	(1,135		)	(6		)	(1,147		)	(6		)
Effect of conversion of New Holdings Units to shares of Athlon’s common stock (a)	—			(215		)	—			616
Diluted undistributed net income attributable to stockholders	$	71,558		$	2,261		$	98,214		$	37,668
Denominator:
Basic weighted average shares outstanding	97,064			76,637			90,904			69,810
Effect of conversion of New Holdings Units to shares of Athlon’s common stock (a)	—			1,856			—			1,856
Diluted weighted average shares outstanding	97,064			78,493			90,904			71,666
Diluted EPS attributable to stockholders	$	0.74		$	0.03		$	1.08		$	0.53

(a) For the three and nine months ended September 30, 2014, 1,855,563 New Holdings Units were outstanding but excluded from the EPS calculations because their effect would have been antidilutive.

Note 11. Incentive Stock Plans

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

The initial aggregate number of shares of common stock reserved for issuance pursuant to awards granted under the Plan is the sum of 8,400,000 shares, subject to adjustment as described below plus an annual increase on the first day of each calendar year beginning January 1, 2014 and ending on and including the last January 1 prior to the expiration date of the Plan, equal to the lessor 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.

On January 1, 2014, the aggregate number of shares of common stock reserved for issuance pursuant to awards granted under the Plan increased to 11,759,386. As of September 30, 2014, there were 9,815,681 shares available for issuance under the Plan.

The Plan does not provide for individual limits on awards that may be granted to any individual participant under the Plan. Rather, the amount of awards to be granted to individual participants are determined by the Board of Directors or the Compensation

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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.

During the nine months ended September 30, 2014 and 2013, Athlon recorded non-cash equity-based compensation expense related to the Plan of $16.0 million and $0.5 million, respectively, 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, 2014 and 2013, Athlon capitalized non-cash equity-based compensation expense related to the Plan of $1.7 million and $37,000, respectively, as a component of “Evaluated, including wells and related equipment” in the accompanying Consolidated Balance Sheets.

Stock awards are scheduled to vest over three years. Certain awards granted to Athlon’s management team vest subject to the relative performance of Athlon’s common stock to that of a designated peer group. The following table summarizes the changes in Athlon’s unvested stock awards for the nine months ended September 30, 2014 (presented at the target level):

			Weighted -
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1	638,913		$	34.88
Granted	1,317,907		45.03
Vested	(209,540	)	37.80
Forfeited	(13,114	)	32.01
Outstanding at September 30	1,734,166		42.27

As of September 30, 2014, there were 1,139,907 unvested stock awards, 872,444 of which were granted during 2014, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of September 30, 2014, there were 594,259 unvested stock awards, 442,592 of which were granted during 2014, in which the vesting is dependent not only on the passage of time and continued employment, but also on the relative performance of Athlon’s common stock to that of a designated peer group (presented at the target level).

During the nine months ended September 30, 2014, there were 285,373 stock awards that vested for which Athlon withheld 86,266 shares of common stock to satisfy employees’ minimum tax withholding obligations related thereto. The total fair value of stock awards that vested during the nine months ended September 30, 2014 was $12.7 million.

None of Athlon’s unvested stock awards are subject to variable accounting. As of September 30, 2014, Athlon had approximately $53.9 million of total unrecognized compensation cost related to unvested stock awards, which is expected to be recognized over a weighted-average period of approximately 2.7 years.

Class B Interests

Holdings’ limited partnership agreement provided for the issuance of Class B limited partner interests. As discussed in “Note 1. Formation of the Company and Description of Business”, in connection with the corporate reorganization, Holdings’ Class B limited partners exchanged their interests for shares of Athlon’s common stock subject to the same conditions and vesting terms. Upon the consummation of the IPO on August 1, 2013, the remaining unvested common stock awards, which were formerly Holdings’ Class B interests, vested and Athlon recognized non-cash equity-based compensation expense of approximately $1.2 million, 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, and capitalized non-cash equity-based compensation expense of $0.4 million as a component of “Evaluated, including wells and related equipment” in the accompanying Consolidated Balance Sheets.

During the nine months ended September 30, 2013, Athlon recorded non-cash equity-based compensation expense related to Class B interests of $1.3 million, 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, Athlon capitalized non-cash equity-based compensation expense related to Class B interests

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

of $0.4 million as a component of “Evaluated, including wells and related equipment” in the accompanying Consolidated Balance Sheets.

Note 12. 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.

Note 13. Related Party Transactions

Services Agreement

Athlon was a party to a Services Agreement which required it to compensate Apollo quarterly for consulting and advisory services, subject to certain quarterly and annual limits. 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, Athlon incurred $0.5 million of advisory fees pursuant to the Services Agreement, which are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. Upon the consummation of the IPO, the Services Agreement was terminated and, in connection with the termination, Athlon 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 remaining term of the Services Agreement.

Exchange Agreement

Upon the consummation of the IPO, Athlon entered into an exchange agreement (the “Exchange Agreement”) with its management team and certain employees who hold New Holdings Units. Under the Exchange Agreement, each such holder (and certain permitted transferees thereof) may, under certain circumstances (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 (an “Exchange”), subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications. As a holder exchanges its New Holdings Units, Athlon’s interest in Holdings will be correspondingly increased.

Tax Receivable Agreement

Upon the consummation of the IPO, Athlon entered into a tax receivable agreement (the “TRA”) with its management team and certain employees who hold New Holdings Units (the “TRA Holders”) that provides for the payment from time to time by Athlon to such TRA Holders of 85% of the amount of the tax benefits, if any, that Athlon actually realizes 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 TRA. These payment obligations are obligations of Athlon and not of Holdings. For purposes of the TRA, 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 Holdings’ assets as a result of the exchanges and had Athlon not entered into the TRA. If Athlon elects to terminate the TRA early, it would be required to make an immediate payment equal to the net present value of the anticipated future tax benefits subject to the TRA (based upon certain assumptions and deemed events set forth in the TRA). In addition, payments due under the TRA will be similarly accelerated following certain mergers, other changes of control, and early payments rights if exercised by the TRA Holders following an Exchange.

On September 27, 2014, concurrently with the execution of the Merger Agreement, Athlon entered into a non-exchange agreement (the “Non-Exchange Agreement”) with the TRA Holders pursuant to which each TRA Holder shall be deemed to have exercised his or her rights under the Exchange Agreement and effected an Exchange in respect of all of his or her New Holdings Units immediately prior to the effective time of the Merger. The Non-Exchange Agreement terminates automatically upon the termination of the Merger Agreement in accordance with its terms.

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Participation of Apollo Global in Debt and Equity Offerings

Apollo Global received a portion of the gross spread as an initial purchaser of the 2022 Notes of $0.5 million. Apollo Global was also an underwriter in Athlon’s April 2014 common stock offering and received a portion of the discounts and commissions paid to the underwriters of approximately $1.0 million. Apollo Global received a portion of the gross spread as an initial purchaser of the 2021 Notes of $0.5 million. Apollo Global was also an underwriter in the IPO and received a portion of the discounts and commissions paid to the underwriters of approximately $0.9 million.

Note 14. Subsequent Events

In November 2014, lenders under the Credit Agreement completed their redetermination of the borrowing base resulting in an increase from $837.5 million to $1.0 billion.

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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 set forth under “Item 1A. Risk Factors” and elsewhere in our 2013 Annual Report on Form 10-K.

Overview

We are an independent exploration and production company focused on the acquisition, development, and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin. The Permian Basin spans portions of Texas and New Mexico and is composed of three primary sub-basins: the Delaware Basin, the Central Basin Platform, and the Midland Basin. All of our properties are located in the Midland Basin. Our drilling activity is currently focused on the low-risk vertical development of stacked pay zones, including the Clearfork, Spraberry, Wolfcamp, Cline, Strawn, Atoka, and Mississippian formations, which we refer to collectively as the Wolfberry play, as well as the horizontal development of these formations. We are a returns-focused organization and have targeted vertical and horizontal development of 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.

Initial Public Offering

On August 7, 2013, we completed our IPO of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $295.7 million, after deducting underwriting discounts and commissions and offering expenses. Upon closing of our IPO, Holdings’ limited partnership agreement was amended and restated to, among other things, modify Holdings’ capital structure by replacing its different classes of interests with a single new class of units, the “New Holdings Units”. Holdings’ management team and certain employees who held Class A limited partner interests now own New Holdings Units and entered into an exchange agreement (the “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 (an “Exchange”), subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications. All other New Holdings Units are held by us.

Merger with Encana

On September 27, 2014, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Encana Corporation (“Encana”) and Alenco Acquisition Company Inc., Encana’s indirect, wholly owned subsidiary (“Alenco”), pursuant to which Alenco will merge with and into Athlon, with Athlon surviving as an indirect, wholly owned subsidiary of Encana (the “Merger”). The Merger Agreement, which was unanimously approved by our Board of Directors and by Encana’s Board of Directors, provides for Encana’s acquisition of all of the issued and outstanding shares of our common stock, par value $0.01 per share, for $58.50 per share in cash (the “Offer”). Completion of the Merger is conditioned upon, among other things, customary closing conditions.

On September 27, 2014, concurrently with the execution of the Merger Agreement, we entered into a non-exchange agreement (the “Non-Exchange Agreement”) with the TRA Holders pursuant to which each TRA Holder shall be deemed to have exercised his or her rights under the Exchange Agreement and effected an Exchange in respect of all of his or her New Holdings Units immediately prior to the effective time of the Merger. The Non-Exchange Agreement terminates automatically upon the termination of the Merger Agreement in accordance with its terms.

How We Evaluate Our Operations

In evaluating our financial results, we focus on the mix of our revenues from oil, natural gas, and NGLs, the average realized price from sales of our production, our production margins, and our capital expenditures. Below are highlights of our financial and operating results for the third quarter of 2014:

· Our oil, natural gas, and NGLs revenues increased 88% to $166.0 million in the third quarter of 2014 as compared to $88.4 million in the third quarter of 2013.

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· Our average daily production volumes increased 120% to 28,556 BOE/D in the third quarter of 2014 as compared to 12,960 BOE/D in the third quarter of 2013. Oil and NGLs represented approximately 83% of our total production volumes in the third quarter of 2014.

· Our average realized oil price decreased 17% to $86.41 per Bbl in the third quarter of 2014 as compared to $104.21 per Bbl in the third quarter of 2013, our average realized natural gas price increased 9% to $3.58 per Mcf in the third quarter of 2014 as compared to $3.28 per Mcf in the third quarter of 2013, and our average realized NGL price decreased 12% to $29.60 per Bbl in the third quarter of 2014 as compared to $33.76 per Bbl in the third quarter of 2013.

· Our production margin increased 86% to $137.7 million in the third quarter of 2014 as compared to $74.2 million in the third quarter of 2013. Total wellhead revenues per BOE decreased 15% and total production expenses per BOE decreased 10%. On a per BOE basis, our production margin decreased 16% to $52.42 per BOE in the third quarter of 2014 as compared to $62.20 per BOE in the third quarter of 2013.

· We invested $579.6 million in oil and natural gas activities, of which $193.5 million was invested in development and exploration activities and $386.1 million was invested in acquisitions of oil and natural gas properties, including the acquisition of certain oil and natural gas properties and related assets in the Midland Basin from Summit for approximately $202.5 million in cash, subject to post-closing adjustments.

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.

Results of Operations

Comparison of Quarter Ended September 30, 2014 to Quarter Ended September 30, 2013

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)
	2014		2013		$			%
Revenues (in thousands):
Oil	$	139,925	$	75,666	$	64,259		85	%
Natural gas	9,795		4,164		5,631			135	%
NGLs	16,321		8,595		7,726			90	%
Total revenues	$	166,041	$	88,425	$	77,616		88	%

Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	86.41	$	104.21	$	(17.80	)	-17	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	83.67	$	94.39	$	(10.72	)	-11	%
Natural gas ($/Mcf)	$	3.58	$	3.28	$	0.30		9	%
NGLs ($/Bbl)	$	29.60	$	33.76	$	(4.16	)	-12	%
Combined ($/BOE) (before impact of cash settled derivatives)	$	63.20	$	74.16	$	(10.96	)	-15	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	61.51	$	68.18	$	(6.67	)	-10	%

Total production volumes:
Oil (MBbls)	1,619		726		893			123	%
Natural gas (MMcf)	2,739		1,270		1,469			116	%
NGLs (MBbls)	551		255		296			116	%
Combined (MBOE)	2,627		1,192		1,435			120	%

Average daily production volumes:
Oil (Bbls/D)	17,601		7,893		9,708			123	%
Natural gas (Mcf/D)	29,769		13,804		15,965			116	%
NGLs (Bbls/D)	5,994		2,767		3,227			117	%
Combined (BOE/D)	28,556		12,960		15,596			120	%

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

	Three months ended September 30,
	2014			2013
Average realized oil price ($/Bbl)	$	86.41		$	104.21
Average NYMEX WTI ($/Bbl)	$	97.21		$	105.82
Differential to NYMEX WTI	$	(10.80	)	$	(1.61	)
Average realized oil price to NYMEX WTI percentage	89		%	98		%

Average realized natural gas price ($/Mcf)	$	3.58		$	3.28
Average NYMEX Henry Hub ($/Mcf)	$	4.06		$	3.58
Differential to NYMEX Henry Hub	$	(0.48	)	$	(0.30	)
Average realized natural gas price to NYMEX Henry Hub percentage	88		%	92		%

Our average oil differential to NYMEX WTI widened to $10.80 per Bbl for the third quarter of 2014 as compared to $1.61 per Bbl for the third quarter of 2013, primarily due to intermittent capacity constraints between the Midland Basin, Cushing, Oklahoma, and Gulf Coast refineries. Our average natural gas differential to NYMEX Henry Hub widened to $0.48 per Mcf for the third quarter of 2014 as compared to $0.30 per Mcf for the third quarter of 2013, primarily due to increases in transportation fees to move our natural gas production out of the Midland Basin.

Oil revenues increased 85% to $139.9 million in the third quarter of 2014 from $75.7 million in the third quarter of 2013 as a result of an increase in our oil production volumes of 893 MBbls, partially offset by a $17.80 per Bbl decrease in our average realized oil price. Our higher oil production increased oil revenues by $93.1 million and was primarily the result of our development program and additional production from our 2014 acquisitions. Our lower average realized oil price decreased oil revenues by $28.8 million and was primarily due to a lower average NYMEX price, which decreased to $97.21 per Bbl in the third quarter of 2014 from $105.82 per Bbl in the third quarter of 2013, and the widening of our oil differentials as previously discussed.

Natural gas revenues increased 135% to $9.8 million in the third quarter of 2014 from $4.2 million in the third quarter of 2013 as a result of an increase in our natural gas production volumes of 1,469 MMcf and a $0.30 per Mcf increase in our average realized natural gas price. Our higher natural gas production increased natural gas revenues by $4.8 million and was primarily the result of our development program, additional production from our 2014 acquisitions, and a reduction in flaring a portion of our natural gas production due to improvements and expansion of natural gas processing infrastructure. 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 $4.06 per Mcf in the third quarter of 2014 from $3.58 per Mcf in the third quarter of 2013, partially offset by the widening of our natural gas differentials as previously discussed.

NGL revenues increased 90% to $16.3 million in the third quarter of 2014 from $8.6 million in the third quarter of 2013 as a result of an increase in our NGL production volumes of 296 MBbls, partially offset by a $4.16 per Bbl decrease in our average realized NGL price. Our higher NGL production increased NGL revenues by $10.0 million and was primarily the result of our development program, additional production from our 2014 acquisitions, and a reduction in flaring as described above. Our lower average realized NGL price decreased NGL revenues by $2.3 million.

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

	Three months ended September 30,					Increase / (Decrease)
	2014			2013		$			%
Expenses (in thousands):
Production:
Lease operating (a)	$	16,677		$	8,762	$	7,915		90	%
Production, severance, and ad valorem taxes	11,647			5,498		6,149			112	%
Total production expenses	28,324			14,260		14,064			99	%
Other:
Depletion, depreciation, and amortization	50,246			23,611		26,635			113	%
General and administrative (b)	15,310			6,696		8,614			129	%
Contract termination fee	—			2,408		(2,408		)	-100	%
Acquisition costs	388			29		359			1238	%
Derivative fair value loss (gain)	(58,526		)	27,037		(85,563		)	-316	%
Accretion of discount on asset retirement obligations	273			174		99			57	%
Total operating	36,015			74,215		(38,200		)	-51	%
Interest	12,502			10,039		2,463			25	%
Income tax provision	42,662			1,934		40,728			2106	%
Total expenses	$	91,179		$	86,188	$	4,991		6	%

Expenses (per BOE):
Production:
Lease operating (a)	$	6.35		$	7.35	$	(1.00	)	-14	%
Production, severance, and ad valorem taxes	4.43			4.61		(0.18		)	-4	%
Total production expenses	10.78			11.96		(1.18		)	-10	%
Other:
Depletion, depreciation, and amortization	19.13			19.80		(0.67		)	-3	%
General and administrative (b)	5.83			5.62		0.21			4	%
Contract termination fee	—			2.02		(2.02		)	-100	%
Acquisition costs	0.15			0.02		0.13			650	%
Derivative fair value loss (gain)	(22.28		)	22.68		(44.96		)	-198	%
Accretion of discount on asset retirement obligations	0.10			0.15		(0.05		)	-33	%
Total operating	13.71			62.25		(48.54		)	-78	%
Interest	4.76			8.42		(3.66		)	-43	%
Income tax provision	16.24			1.62		14.62			902	%
Total expenses	$	34.71		$	72.29	$	(37.58	)	-52	%

(a) For the third quarter of 2014, includes non-cash equity-based compensation of $0.7 million ($0.26 per BOE) and non-cash LOE for oil inventory assumed in acquisitions of $0.5 million ($0.19 per BOE). For the third quarter of 2013, includes non-cash equity-based compensation of $0.2 million ($0.16 per BOE).

(b) For the third quarter of 2014, includes non-cash equity-based compensation of $6.9 million ($2.63 per BOE), Encana merger costs of $1.8 million ($0.68 per BOE), and secondary offering costs of $0.3 million ($0.12 per BOE). For the third quarter of 2013, includes non-recurring IPO costs of $2.1 million ($1.77 per BOE), non-cash equity-based compensation of $0.5 million ($0.40 per BOE), and corporate reorganization costs of $0.2 million ($0.13 per BOE).

Production expenses. LOE increased 90% to $16.7 million in the third quarter of 2014 from $8.8 million in the third quarter of 2013 as a result of an increase in production volumes as previously discussed, which contributed $10.5 million of additional LOE, partially offset by a $1.00 decrease in the average per BOE rate, which would have reduced LOE by $2.6 million if production had been unchanged. The decrease in our average LOE per BOE rate was attributable to our close control of well servicing costs and leverage of our centralized service facilities and water handling systems.

Production, severance, and ad valorem taxes increased 112% to $11.6 million in the third quarter of 2014 from $5.5 million in the third quarter of 2013 primarily due to higher wellhead revenues as previously discussed. As a percentage of wellhead revenues, production, severance, and ad valorem taxes increased to 7.0% in the third quarter of 2014 as compared to 6.2% in the third quarter of 2013, primarily due to the decrease in average realized oil prices as previously discussed and the increase in natural gas revenues as a percentage of total revenues. Ad valorem taxes are paid based on prior year commodity prices and valuations of oil and natural gas properties, whereas production taxes are based on current year commodity prices and production volumes. Texas generally imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production.

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Depreciation, depletion, and amortization (“DD&A”). DD&A expense increased 113% to $50.2 million in the third quarter of 2014 from $23.6 million in the third quarter of 2013 primarily due to an increase in production volumes as previously discussed and an increase in our asset base subject to amortization as a result of our drilling activity and additional properties added from our 2014 acquisitions.

General and administrative (“G&A”). G&A expense, excluding non-cash equity-based compensation, increased 35% to $8.4 million in the third quarter of 2014 from $6.2 million in the third quarter of 2013 primarily due to (i) higher payroll and payroll-related costs, including mid-year performance bonuses, as we continue to add employees in order to accommodate our growing drilling program, (ii) additional expenses related to being a public company, (iii) $1.8 million of costs related to the pending merger with Encana, and (iv) $0.3 million of nonrecurring offering costs, partially offset by $2.1 million of non-recurring IPO costs in the third quarter of 2013. Non-cash equity-based compensation allocated to G&A expense increased to $6.9 million in the third quarter of 2014 from $0.5 million in the third quarter of 2013 primarily due to stock awards granted to employees as part of our incentive program.

Contract termination fee. Holdings was a party to a Services Agreement which required it 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 remaining term of the Services Agreement.

Derivative fair value loss (gain). During the third quarter of 2014, we recorded a $58.5 million derivative fair value gain as compared to a $27.0 million derivative fair value loss in the third quarter of 2013. 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 2014 of $4.4 million as compared to $7.1 million during the third quarter of 2013.

Interest expense. Interest expense increased 25% to $12.5 million in the third quarter of 2014 from $10.0 million in the third quarter of 2013 due to higher long-term debt balances. Our weighted-average total debt increased to $1.2 billion for the third quarter of 2014 as compared to $527.7 million for the third quarter of 2013, primarily due to (i) funding requirements to develop our oil and natural gas properties that are not covered by our operating cash flows and (ii) funding of acquisitions.

Our weighted-average interest rate, before capitalized interest, decreased to 6.8% for the third quarter of 2014 as compared to 7.5% for the third quarter of 2013, primarily due to the issuance of our 6% senior notes in April 2014.

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

	Three months ended September 30,						Increase /
	2014			2013			(Decrease)
	(in thousands)
Credit agreement	$	1,156		$	417		$	739
73/8% senior notes	9,239			9,147			92
6% senior notes	9,770			—			9,770
Amortization of debt issuance costs	967			545			422
Less: interest capitalized	(8,630		)	(70		)	(8,560		)
Total	$	12,502		$	10,039		$	2,463

Income taxes. In the third quarter of 2014, we recorded an income tax provision of $42.7 million as compared to $1.9 million in the third quarter of 2013. In the third quarter of 2014, we had income before income taxes and noncontrolling interest of $117.6 million as compared to $4.2 million in the third quarter of 2013. Our effective tax rate decreased to 36.3% in the third quarter of 2014 as compared to 46.0% in the third quarter of 2013, primarily due to a decrease in permanent differences related to the initial public offering in 2013 and a reduction in our projected annual effective state income tax rate for 2014.

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Comparison of Nine Months Ended September 30, 2014 to Nine Months Ended September 30, 2013

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)
	2014		2013		$			%
Revenues (in thousands):
Oil	$	341,144	$	175,934	$	165,210		94	%
Natural gas	25,907		11,894		14,013			118	%
NGLs	41,169		20,508		20,661			101	%
Total revenues	$	408,220	$	208,336	$	199,884		96	%

Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	90.57	$	94.43	$	(3.86	)	-4	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	85.85	$	90.19	$	(4.34	)	-5	%
Natural gas ($/Mcf)	$	3.97	$	3.42	$	0.55		16	%
NGLs ($/Bbl)	$	31.77	$	30.87	$	0.90		3	%
Combined ($/BOE) (before impact of cash settled derivatives)	$	66.39	$	67.07	$	(0.68	)	-1	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	63.50	$	64.52	$	(1.02	)	-2	%

Total production volumes:
Oil (MBbls)	3,766		1,863		1,903			102	%
Natural gas (MMcf)	6,520		3,474		3,046			88	%
NGLs (MBbls)	1,296		664		632			95	%
Combined (MBOE)	6,149		3,106		3,043			98	%

Average daily production volumes:
Oil (Bbls/D)	13,797		6,824		6,973			102	%
Natural gas (Mcf/D)	23,883		12,725		11,158			88	%
NGLs (Bbls/D)	4,747		2,433		2,314			95	%
Combined (BOE/D)	22,524		11,378		11,146			98	%

	Nine months ended September 30,
	2014			2013
Average realized oil price ($/Bbl)	$	90.57		$	94.43
Average NYMEX WTI ($/Bbl)	$	99.60		$	98.17
Differential to NYMEX WTI	$	(9.03	)	$	(3.74	)
Average realized oil price to NYMEX WTI percentage	91		%	96		%

Average realized natural gas price ($/Mcf)	$	3.97		$	3.42
Average NYMEX Henry Hub ($/Mcf)	$	4.54		$	3.67
Differential to NYMEX Henry Hub	$	(0.57	)	$	(0.25	)
Average realized natural gas price to NYMEX Henry Hub percentage	87		%	93		%

Our average oil differential to NYMEX WTI widened to $9.03 per Bbl for the first nine months of 2014 as compared to $3.74 per Bbl for the first nine months of 2013, primarily due to intermittent capacity constraints between the Midland Basin, Cushing, Oklahoma, and Gulf Coast refineries. Our average natural gas differential to NYMEX Henry Hub widened to $0.57 per Mcf for the first nine months of 2014 as compared to $0.25 per Mcf for the first nine months of 2013, primarily due to increases in transportation fees to move our natural gas production out of the Midland Basin.

Oil revenues increased 94% to $341.1 million in the first nine months of 2014 from $175.9 million in the first nine months of 2013 as a result of an increase in our oil production volumes of 1,903 MBbls, partially offset by a $3.86 per Bbl decrease in our

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average realized oil price. Our higher oil production increased oil revenues by $179.7 million and was primarily the result of our development program and additional production from our 2014 acquisitions. Our lower average realized oil price decreased oil revenues by $14.5 million and was primarily due to the widening of our oil differentials as previously discussed, partially offset by a higher average NYMEX price, which increased to $99.60 per Bbl in the first nine months of 2014 from $98.17 per Bbl in the first nine months of 2013.

Natural gas revenues increased 118% to $25.9 million in the first nine months of 2014 from $11.9 million in the first nine months of 2013 as a result of an increase in our natural gas production volumes of 3,046 MMcf and a $0.55 per Mcf increase in our average realized natural gas price. Our higher natural gas production increased natural gas revenues by $10.4 million and was primarily the result of our development program, additional production from our 2014 acquisitions, and a reduction in flaring a portion of our natural gas production due to improvements and expansion of natural gas processing infrastructure. Our higher average realized natural gas price increased natural gas revenues by $3.6 million and was primarily due to a higher average NYMEX price, which increased to $4.54 per Mcf in the first nine months of 2014 from $3.67 per Mcf in the first nine months of 2013, partially offset by the widening of our natural gas differentials as previously discussed.

NGL revenues increased 101% to $41.2 million in the first nine months of 2014 from $20.5 million in the first nine months of 2013 as a result of an increase in our NGL production volumes of 632 MBbls and a $0.90 per Bbl increase in our average realized NGL price. Our higher NGL production increased NGL revenues by $19.5 million and was primarily the result of our development program, additional production from our 2014 acquisitions, and a reduction in flaring as described above. Our higher average realized NGL price increased NGL revenues by $1.2 million.

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

	Nine months ended September 30,					Increase / (Decrease)
	2014			2013		$			%
Expenses (in thousands):
Production:
Lease operating (a)	$	42,126		$	23,774	$	18,352		77	%
Production, severance, and ad valorem taxes	27,060			13,549		13,511			100	%
Total production expenses	69,186			37,323		31,863			85	%
Other:
Depletion, depreciation, and amortization	116,792			62,022		54,770			88	%
General and administrative (b)	38,718			13,543		25,175			186	%
Contract termination fee	—			2,408		(2,408		)	-100	%
Acquisition costs	2,213			180		2,033			1129	%
Derivative fair value loss (gain)	(14,949		)	21,331		(36,280		)	-170	%
Accretion of discount on asset retirement obligations	690			485		205			42	%
Total operating	212,650			137,292		75,358			55	%
Interest	35,208			26,595		8,613			32	%
Income tax provision	57,916			6,805		51,111			751	%
Total expenses	$	305,774		$	170,692	$	135,082		79	%

Expenses (per BOE):
Production:
Lease operating (a)	$	6.85		$	7.65	$	(0.80	)	-10	%
Production, severance, and ad valorem taxes	4.40			4.36		0.04			1	%
Total production expenses	11.25			12.01		(0.76		)	-6	%
Other:
Depletion, depreciation, and amortization	18.99			19.97		(0.98		)	-5	%
General and administrative (b)	6.30			4.36		1.94			44	%
Contract termination fee	—			0.78		(0.78		)	-100	%
Acquisition costs	0.36			0.06		0.30			500	%
Derivative fair value loss (gain)	(2.43		)	6.87		(9.30		)	-135	%
Accretion of discount on asset retirement obligations	0.11			0.16		(0.05		)	-31	%
Total operating	34.58			44.21		(9.63		)	-22	%
Interest	5.73			8.56		(2.83		)	-33	%
Income tax provision	9.42			2.19		7.23			330	%
Total expenses	$	49.73		$	54.96	$	(5.23	)	-10	%

(a) For the first nine months of 2014, includes non-cash LOE for oil inventory assumed in acquisitions of $2.2 million ($0.35 per BOE) and non-cash equity-based compensation of $1.4 million ($0.22 per BOE). For the first nine months of 2013, includes non-cash equity-based compensation of $0.2 million ($0.07 per BOE).

(b) For the first nine months of 2014, includes non-cash equity-based compensation of $14.6 million ($2.38 per BOE), Encana merger costs of $1.8 million ($0.29 per BOE), and secondary offering costs of $1.5 million ($0.25 per BOE). For the first nine months of 2013, includes non-recurring IPO costs of $2.1 million ($0.68 per BOE), corporate reorganization costs of $0.7 million ($0.21 per BOE), non-cash equity-based compensation of $0.6 million ($0.18 per BOE), and advisory fees of $0.5 million ($0.16 per BOE).

Production expenses. LOE increased 77% to $42.1 million in the first nine months of 2014 from $23.8 million in the first nine months of 2013 as a result of an increase in production volumes as previously discussed, which contributed $23.3 million of additional LOE, partially offset by a $0.80 decrease in the average per BOE rate, which would have reduced LOE by $4.9 million if production had been unchanged. The decrease in our average LOE per BOE rate was attributable to our close control of well servicing costs and leverage of our centralized service facilities and water handling systems.

Production, severance, and ad valorem taxes increased 100% to $27.1 million in the first nine months of 2014 from $13.5 million in the first nine months of 2013 primarily due to higher wellhead revenues as previously discussed. As a percentage of wellhead revenues, production, severance, and ad valorem taxes remained relatively consistent at 6.6% in the first nine months of 2014 as compared to 6.5% in the first nine months of 2013. Ad valorem taxes are paid based on prior year commodity prices and valuations of oil and natural gas properties, whereas production taxes are based on current year commodity prices and production volumes.

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DD&A. DD&A expense increased 88% to $116.8 million in the first nine months of 2014 from $62.0 million in the first nine months of 2013 primarily due to an increase in production volumes as previously discussed and an increase in our asset base subject to amortization as a result of our drilling activity and additional properties added from our 2014 acquisitions.

G&A. G&A expense, excluding non-cash equity-based compensation, increased 86% to $24.1 million in the first nine months of 2014 from $13.0 million in the first nine months of 2013 primarily due to (i) higher payroll and payroll-related, including mid-year performance bonuses, as we continue to add employees in order to accommodate our growing drilling program, (ii) additional expenses related to being a public company, (iii) $1.8 million of costs related to the pending merger with Encana, and (iv) $1.5 million of nonrecurring offering costs, partially offset by $2.1 million of non-recurring IPO costs in the third quarter of 2013. Non-cash equity-based compensation allocated to G&A expense increased to $14.6 million in the first nine months of 2014 from $0.6 million in the first nine months of 2013 primarily due to stock awards granted to employees as part of our incentive program.

Derivative fair value loss (gain). During the first nine months of 2014, we recorded a $14.9 million derivative fair value gain as compared to a $21.3 million derivative fair value loss in the first nine months of 2013. 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 2014 of $17.8 million as compared to $7.9 million during the first nine months of 2013.

Interest expense. Interest expense increased 32% to $35.2 million in the first nine months of 2014 from $26.6 million in the first nine months of 2013 due to higher long-term debt balances. Our weighted-average total debt increased to $914.5 million for the first nine months of 2014 as compared to $481.1 million for the first nine months of 2013, primarily due to (i) funding requirements to develop our oil and natural gas properties that are not covered by our operating cash flows and (ii) funding of our 2014 acquisitions.

Our weighted-average interest rate, before capitalized interest, decreased to 7.1% for the first nine months of 2014 as compared to 7.4% for the first nine months of 2013, primarily due to the write off of unamortized debt issuance costs in the second quarter of 2013 and the issuance of our 6% senior notes in April 2014.

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

	Nine months ended September 30,						Increase /
	2014			2013			(Decrease)
	(in thousands)
Credit agreement	$	2,443		$	3,027		$	(584	)
73/8% senior notes	27,733			16,854			10,879
6% senior notes	16,285			—			16,285
Former second lien term loan	—			2,777			(2,777		)
Write off of debt issuance costs	—			2,838			(2,838		)
Amortization of debt issuance costs	2,325			1,280			1,045
Less: interest capitalized	(13,578		)	(181		)	(13,397		)
Total	$	35,208		$	26,595		$	8,613

Income taxes. In the first nine months of 2014, we recorded an income tax provision of $57.9 million as compared to $6.8 million in the first nine months 2013. In the first nine months of 2014, we had income before income taxes and noncontrolling interest of $160.4 million as compared to $44.5 million in the first nine months of 2013. Our effective tax rate increased to 36.1% in the first nine months of 2014 as compared to 15.3% in the first nine months of 2013 as a result of our corporate reorganization in April 2013 in which Athlon (a C-corporation) obtained substantially all of Holdings’ interests, our accounting predecessor, which is 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,
	2014		2013		2014		2013
	(in thousands)
Development (a)	$	70,064	$	42,430	$	206,175	$	132,883
Exploration (b)	123,430		65,402		297,857		145,435
Total	$	193,494	$	107,832	$	504,032	$	278,318

(a) Includes asset retirement obligations incurred of $0.3 million and $0.2 million during the three months ended September 30, 2014 and 2013, respectively, and $0.7 million and $0.4 million during the nine months ended September 30, 2014 and 2013, respectively.

(b) Includes asset retirement obligations incurred of $0.3 million and $0.1 million during the three months ended September 30, 2014 and 2013, respectively, and $0.7 million and $0.3 million during the nine months ended September 30, 2014 and 2013, 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 exploration expenditures primarily relate to the drilling of exploratory wells, seismic costs, delay rentals, and geological and geophysical costs.

Our development and exploration activities in the first nine months of 2014 were higher than in the first nine months of 2013 primarily due to our higher rig count, including the addition of horizontal drilling rigs.

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,
	2014		2013		2014		2013
	(in thousands)
Acquisitions of evaluated properties (a)	$	184,112	$	3,113	$	681,866	$	5,883
Acquisitions of unevaluated properties	201,966		17,009		686,424		30,985
Total	$	386,078	$	20,122	$	1,368,290	$	36,868

(a) Includes asset retirement obligations incurred of $1.0 million and $0.1 million during the three months ended September 30, 2014 and 2013, respectively, and $3.1 million and $0.3 million during the nine months ended September 30, 2014 and 2013, respectively.

In the third quarter of 2014, we completed the acquisition of certain oil and natural gas properties and related assets in the Midland Basin from Summit for approximately $202.5 million in cash, subject to post-closing adjustments. In the second quarter of 2014, we completed the acquisitions of certain oil and natural gas properties and related assets in the Midland Basin from Hibernia and Piedra for approximately $394.0 million and $292.8 million in cash, respectively, subject to post-closing adjustments. These amounts are included in the above table.

Funding of working capital. As of September 30, 2014 and December 31, 2013, our working capital (defined as total current assets less total current liabilities) was a $95.7 million deficit and a $45.4 million surplus, respectively. The decrease in working capital was primarily due to our 2014 acquisitions. 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

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the remainder of 2014, we expect to have a working capital deficit primarily due to amounts accrued related to our extensive development activities. We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs, drilling 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. We have 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. Other than the issuance of our 6% senior notes in May 2014, neither the amounts nor the terms of any other commitments or contingent obligations have changed significantly from the year-end amounts reflected in our 2013 Annual Report on Form 10-K. Our commodity derivative contracts, which are recorded at fair value in our consolidated balance sheets, are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Our long-term debt is discussed in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and below under “—Liquidity”.

Please read “Capital Commitments, Capital Resources, and Liquidity—Capital commitments—Contractual obligations” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2013 Annual Report on Form 10-K for additional information regarding our commitments and obligations.

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 have no 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 /
	2014			2013			(Decrease)
	(in thousands)
Net cash provided by operating activities	$	269,669		$	136,775		$	132,894
Net cash used in investing activities	(1,817,882		)	(295,003		)	(1,522,879		)
Net cash provided by financing activities	1,440,185			346,245			1,093,940
Net increase (decrease) in cash	$	(108,028	)	$	188,017		$	(296,045	)

Cash flows from operating activities. Cash provided by operating activities increased $132.9 million to $269.7 million in the first nine months of 2014 from $136.8 million in the first nine months of 2013, primarily due to an increase in our production margin as our total production volumes increased 98%, partially offset by increased expenses as a result of having more producing wells in the first nine months of 2014 as compared to the first nine months of 2013.

Cash flows used in investing activities. Cash used in investing activities increased $1.5 billion to $1.8 billion in the first nine months of 2014 from $295.0 million in the first nine months of 2013, primarily due to a $1.3 billion increase in amounts paid to acquire oil and natural gas properties and a $193.4 million increase in amounts paid to develop oil and natural gas properties. The increase in our development expenditures was primarily due to our higher rig count, including the addition of horizontal drilling rigs.

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

During the first nine months of 2014, we received net cash of $1.4 billion from financing activities, including $570.8 million of net proceeds from issuances of shares of our common stock, $639.1 million of net proceeds from the issuance of our 6% senior notes, and net borrowings of $236 million under our credit agreement. Net borrowings increased the outstanding borrowings under our credit agreement from none at December 31, 2013 to $236 million at September 30, 2014.

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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 73/8% 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.

Liquidity

Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our credit agreement. Since we operate a majority of our wells, we have the ability to adjust our capital expenditures. We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and expected future availability under our credit agreement will be sufficient to fund our operations and drilling 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.

Our drilling capital expenditures and other future expenditures are 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 drilling capital expenditures using internally generated cash flows and availability under our credit agreement.

Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil, natural gas, and NGL prices. During the first nine months of 2014, our average realized natural gas and NGL prices increased by 16% and 3%, respectively, as compared to the first nine months of 2013, while our average realized oil price decreased by 4%. 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 oil swaps that will provide stable cash flows on a portion of our oil production. Currently, we have the following oil swaps:

Period	Average Daily Swap Volume	Weighted- Average Swap Price
	(Bbl)	(per Bbl)
Q4 2014	10,961	$	92.31

Q1 2015	12,800	92.12
Q2 2015	12,800	92.12
Q3 2015	11,800	93.69
Q4 2015	11,800	93.69

Q1 2016	2,500	92.35
Q2 2016	2,500	92.35

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 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. Borrowings under our credit agreement may be repaid from time to time without penalty. As of September 30, 2014, the borrowing base was $837.5 million and there were $236 million of outstanding borrowings, $601.5 million of borrowing capacity, and no outstanding letters of credit under our credit agreement.

Obligations under our credit agreement are secured by a first-priority security interest in substantially all of Holdings’ proved reserves.

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%.

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

· a prohibition against incurring additional 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 4.5 to 1.0; and

As of September 30, 2014, we were in compliance with all covenants in our credit agreement.

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 under 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.

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Senior notes. In April 2013, Holdings issued $500 million aggregate principal amount of 73/8% senior unsecured notes due 2021 (the “2021 Notes”). We are an unconditional guarantor of the 2021 Notes. Under the indenture, starting on April 15, 2016, we will be able to redeem some or all of the 2021 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 2021 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 2021 Notes, plus an “applicable premium”, plus accrued and unpaid interest to the date of redemption. Certain asset dispositions or a change of control will be triggering events that may require us to repurchase all or any part of a noteholder’s 2021 Notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, up to but excluding the date of repurchase. Interest on the senior notes is payable in cash semi-annually in arrears, commencing on October 15, 2013, through maturity.

On May 1, 2014, Holdings completed a private placement of $650 million aggregate principal amount of 6% senior unsecured notes due 2022 (the “2022 Notes”). We are an unconditional guarantor of the 2022 Notes. Under the indenture, starting on May 1, 2017, we will be able to redeem some or all of the 2022 Notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption. Prior to May 1, 2017, we will be able, at its option, to redeem up to 35% of the aggregate principal amount of the 2022 Notes at a price of 106% 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 May 1, 2017, we may redeem some or all of the 2022 Notes at a redemption price equal to 100% of the principal amount of the 2022 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, 2015, we may redeem all, but not less than all, of the 2022 Notes at 110% of the principal amount thereof plus accrued and unpaid interest to, but not including, the redemption date. Certain asset dispositions or a change of control that occurs after July 15, 2015 will be triggering events that may require us to repurchase all or any part of a noteholder’s 2022 Notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, up to but excluding the date of repurchase. Interest on the 2022 Notes is payable in cash semi-annually in arrears, commencing on November 1, 2014, through maturity.

The indentures governing our senior notes contain 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 our senior notes may be declared immediately due and payable.

As of September 30, 2014, we were in compliance with all covenants in our senior notes.

Capitalization. At September 30, 2014, we had total assets of $3.1 billion and total capitalization of $2.7 billion, of which 49% was represented by equity and 51% by long-term debt. At December 31, 2013, we had total assets of $1.4 billion and total capitalization of $1.1 billion, of which 56% was represented by equity and 44% by long-term debt. 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.

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:

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	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	86.41	$	104.21	$	90.57	$	94.43
Oil ($/Bbl) (after impact of cash settled derivatives)	83.67		94.39		85.85		90.19
Natural gas ($/Mcf)	3.58		3.28		3.97		3.42
NGLs ($/Bbl)	29.60		33.76		31.77		30.87
Combined ($/BOE) (before impact of cash settled derivatives)	63.20		74.16		66.39		67.07
Combined ($/BOE) (after impact of cash settled derivatives)	61.51		68.18		63.50		64.52

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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2013 Annual Report on Form 10-K for information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. 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.

Derivative policy

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

Counterparties

At September 30, 2014, we had committed 10% or greater (in terms of fair market value) of our oil derivative contracts in asset positions from the following counterparties:

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	Fair Market Value of
	Oil Derivative
	Contracts
Counterparty	Committed
	(in thousands)
Citibank	$	7,524
Barclays PLC	6,187
Scotiabank	4,953
J Aron	4,397

We do not require collateral from our counterparties for entering into derivative instruments, so in order to mitigate the credit risk associated with such derivative instruments, we enter into an International Swap Dealers Association Master Agreement (“ISDA Agreement”) with each of our counterparties. The ISDA Agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each derivative transaction between the counterparty and us separately, the ISDA Agreement enables the counterparty and us to aggregate all trades under such agreement 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 trade can trigger rights to terminate all trades with such counterparty that are subject to the ISDA Agreement; 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 nine institutions, all of which are rated A- or better by Standard & Poor’s and Baa2 or better by Moody’s and eight of which are lenders under our credit agreement.

Commodity price sensitivity

Commodity prices are often subject to significant volatility due to many factors that are beyond our control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters. We manage oil price risk with swaps, which provide a fixed price for a notional amount of sales volumes. The following table summarizes our open commodity derivative contracts as of September 30, 2014:

Period	Average Daily Swap Volume	Weighted- Average Swap Price		Net Asset Fair Market Value
	(Bbl)	(per Bbl)		(in thousands)
Q4 2014	10,961	$	92.31	$	2,168

Q1 2015	12,800	92.12
Q2 2015	12,800	92.12
Q3 2015	11,800	93.69
Q4 2015	11,800	93.69
2015	12,296	92.88		22,727

Q1 2016	2,500	92.35
Q2 2016	2,500	92.35
2016	1,243	92.35		2,718
				$	27,613

We are also a party to Midland-Cushing basis differential swaps for 6,000 Bbls/D at $5.19/Bbl for 2015. At September 30, 2014, the fair value of these contracts was a net liability of approximately $1.3 million.

As of September 30, 2014, the fair market value of our oil derivative contracts was a net asset of $26.3 million. Based on our open commodity derivative positions at September 30, 2014, a 10% decrease in the NYMEX WTI price would increase our net commodity derivative asset by approximately $51.2 million, while a 10% increase in the NYMEX WTI price would change our net commodity derivative asset to a net commodity derivative liability of approximately $24.9 million.

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Interest rate sensitivity

At September 30, 2014, we had outstanding debt of $1.4 billion, $500 million of which bears interest at a fixed rate of 73/8%, $650 million of which bears interest at a fixed rate of 6%, and $236 million of which consisted of outstanding borrowings under our credit agreement and is subject to floating market rates of interest that are linked to the Eurodollar rate. At this level of floating rate debt, if the Eurodollar rate increased 10%, we would incur an additional $0.4 million of interest expense per year, and if the Eurodollar rate decreased 10%, we would incur $0.4 million less. At September 30, 2014, the fair value of our senior notes was approximately $1.2 billion.

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, 2014 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. However, we are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of its internal control over financial reporting. We will be required to make our first assessment of internal control over financial reporting under Section 404 for our 2014 Annual Report on Form 10-K.

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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 “Item 1A. Risk Factors” and elsewhere in our 2013 Annual Report on Form 10-K, which could materially affect our business, financial condition, and/or future results. The risks described in our 2013 Annual Report on Form 10-K 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 6. Exhibits

Exhibit No.		Description

3.1		Amended and Restated Certificate of Incorporation of Athlon Energy Inc. (incorporated by reference to Exhibit 3.1 of Athlon’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, filed with the SEC on August 14, 2013).
3.2		Amended and Restated Bylaws of Athlon Energy Inc. (incorporated by reference to Exhibit 3.2 of Athlon’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, filed with the SEC on August 14, 2013).
10.1		Purchase and Sale Agreement, dated as of July 25, 2014, by and among the parties thereto (incorporated by reference to Exhibit 2.1 of Athlon’s Current Report on Form 8-K, filed with the SEC on September 4, 2014).
10.2+		Form of Restricted Stock Grant Notice—Executive (incorporated by reference to Exhibit (e)(12) to Athlon’s Schedule 14D-9, filed with the SEC on October 10, 2014).
10.3		Agreement and Plan of Merger, dated as of September 27, 2014, by and among Encana Corporation, Alenco Acquisition Company Inc., and Athlon Energy Inc. (incorporated by reference to Exhibit 2.1 of Athlon’s Current Report on Form 8-K, filed with the SEC on October 2, 2014).
10.4		Amendment to Agreement and Plan of Merger, dated as of November 3, 2014, by and among Encana Corporation, Alenco Acquisition Company Inc., and Athlon Energy Inc. (incorporated by reference to Exhibit 2.1 of Athlon’s Current Report on Form 8-K, filed with the SEC on November 7, 2014).
10.5+		Form of Amendment to Employment Agreement, dated as of September 27, 2014, by and between Athlon Holdings LP and Robert C. Reeves (incorporated by reference to Exhibit 10.1 of Athlon’s Current Report on Form 8-K, filed with the SEC on October 2, 2014).
10.6+		Form of Amendment to Employment Agreement, dated as of September 27, 2014, by and between Athlon Holdings LP and each named executive officer (other than Robert C. Reeves) (incorporated by reference to Exhibit 10.2 of Athlon’s Current Report on Form 8-K, filed with the SEC on October 2, 2014).
10.7		Form of Non-Exchange Agreement, dated September 27, 2014, by and among Encana Corporation, Alenco Acquisition Company Inc., Athlon Energy Inc., and certain unitholders of Athlon Holdings LP named therein (incorporated by reference to Exhibit (d)(5) to the Schedule TO of Encana Corporation and Alenco Acquisition Company Inc., filed with the SEC on October 10, 2014).
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 12, 2014

Athlon Energy Inc. - FORM 10-Q - November 12, 2014

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