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 ~~June~~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 Numbers:

Athlon Holdings LP 333-195506

Athlon Finance Corp. 333-195506-02

ATHLON HOLDINGS LP

ATHLON FINANCE CORP.

(Exact name of registrant as specified in its charter)

Delaware		45-2817212
Delaware		46-2465554
(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.

Athlon Holdings LP Yes ox No xo Athlon Finance Corp. Yes ox No xo

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).

Athlon Holdings LP	Yes x No o
Athlon Finance Corp.	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.

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Athlon Holdings LP	Yes o No x
Athlon Finance Corp.	Yes o No x

Number of units of Athlon Holdings LP outstanding as of ~~August~~November 2012, 2014: 98100,~~790~~315,~~902~~039. All of Athlon Finance Corp.’s common stock is directly owned by Athlon Holdings LP.

This combined Form 10-Q is filed separately by Athlon Holdings LP and Athlon Finance Corp. Athlon Finance Corp. meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.

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ATHLON HOLDINGS LP

ATHLON FINANCE CORP.

INDEX

		Page	~~Page~~
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013		1
	Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	1
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013		2
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013	2
	Consolidated Statement of Changes in Partner’s Equity for the Six Months Ended June 30, 2014		3
	Consolidated Statement of Changes in Partner’s Equity for the Nine Months Ended September 30, 2014	3
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013		4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013	4
	Notes to Consolidated Financial Statements	5	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33	32
Item 4.	Controls and Procedures	35	33
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	36	34
Item 1A.	Risk Factors	36	34
Item 6.	Exhibits	36	34

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 “Cautionary Note Regarding Forward Looking Information”, “Risk Factors”, and elsewhere in our final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act of 1933, as amended (the “Securities Act”), on July 24, 2014. 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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ATHLON HOLDINGS LP

ATHLON FINANCE CORP.

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.

· FASB. Financial Accounting Standards Board.

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

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

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

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

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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 HOLDINGS LP

CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30,			December 31,
	September 30,			December 31,
	2014			2013
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	~~242~~4,~~895~~847		$	113,025
Accounts receivable	8197,~~463~~162			48,238
Inventory	1,176			928
Derivatives, at fair value	16,948			—
Deferred taxes	139			10
Inventory	1,910			928
Other	354			487
Deferred taxes	—			10
Total current assets	326,027			162,688
Other	1,171			487
Total current assets	122,038			162,688
Properties and equipment, at cost - full cost method:
Evaluated, including wells and related equipment	2,~~070~~525,~~655~~499			1,244,178
Unevaluated	~~555~~678,~~905~~879			89,859
Accumulated depletion, depreciation, and amortization	(~~227~~277,~~195~~347		)	(160,779		)
	2,399,365			1,173,258
	2,927,031			1,173,258
Derivatives, at fair value	~~318~~9,327			2,330
Debt issuance costs	25,~~908~~101			14,679
Other	2,~~097~~393			1,447
Total assets	$	23,~~753~~085,~~715~~890		$	1,354,402
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	~~9,861~~220		$	459
Intercompany	1,~~644~~754			1,240
Accrued liabilities:
Lease operating	910,~~208~~631			6,563
Production, severance, and ad valorem taxes	610,~~949~~462			2,550
Development capital	~~120~~118,~~523~~105			68,059
Interest	1433,~~293~~337			7,790
Derivatives, at fair value	~~33,542~~—			8,354
Revenue payable	3235,~~827~~233			20,513
Other	9,555			2,795
Deferred taxes	251			—
Total current liabilities	238,402			118,323
Other	4,819			2,795
Asset retirement obligations, net of current portion	10,496			6,795
Total current liabilities	214,812			118,323
Long-term debt	1,150,000			500,000
Asset retirement obligations, net of current portion	12,328			6,795
Deferred taxes	4,815			3,936
Long-term debt	1,386,000			500,000
Derivatives, at fair value	3,320			—
Deferred taxes	6,836			3,936
Other	~~140~~152			101
Total liabilities	1,~~407~~620,~~173~~128			629,155
Commitments and contingencies
Partners’ equity	1,~~346~~465,~~542~~762			725,247
Total liabilities and partners’ equity	$	23,~~753~~085,~~715~~890		$	1,354,402

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

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ATHLON HOLDINGS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)

	Three months ended June 30,						Six months ended June 30,
	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
Revenues:
Oil	$	~~114~~139,~~137~~925		$	5475,~~609~~666		$	~~201~~341,~~219~~144		$	~~100~~175,~~268~~934
Natural gas	89,~~687~~795			4,~~363~~164			1625,~~112~~907			711,~~730~~894
Natural gas liquids	1316,~~686~~321			68,~~193~~595			2441,~~848~~169			1120,~~913~~508
Total revenues	~~136~~166,~~510~~041			6588,~~165~~425			~~242~~408,~~179~~220			~~119~~208,~~911~~336
Expenses:
Production:
Lease operating	1416,~~713~~677			78,~~775~~762			2542,~~449~~126			1523,~~012~~774
Production, severance, and ad valorem taxes	811,~~661~~647			45,~~312~~498			1527,~~413~~060			813,~~051~~549
Depletion, depreciation, and amortization	3850,~~470~~246			2023,~~358~~611			66116,~~546~~792			3862,~~411~~022
General and administrative	1314,~~430~~306			36,~~558~~454			2035,~~858~~164			613,~~840~~294
Acquisition costs	1,207			94			1,825			151
Contract termination fee	—			2,408			—			2,408
Derivative fair value loss (gain)	32,397			(12,555		)	43,577			(5,706		)
Acquisition costs	388			29			2,213			180
Accretion of discount on asset retirement obligations	222			162			417			311
Derivative fair value loss (gain)	(58,526		)	27,037			(14,949		)	21,331
Total expenses	109,100			23,704			174,085			63,070
Accretion of discount on asset retirement obligations	273			174			690			485
Operating income	27,410			41,461			68,094			56,841
Total expenses	35,011			73,973			209,096			137,043
Operating income	131,030			14,452			199,124			71,293
Other income (expenses):
Interest	(1312,~~528~~502		)	(1210,~~082~~039		)	(2235,~~706~~208		)	(1626,~~556~~595		)
Other	2336			—30			2662			—30
Total other expenses	(1312,~~505~~466		)	(1210,~~082~~009		)	(2235,~~680~~146		)	(1626,~~556~~565		)
Income before income taxes	13118,~~905~~564			294,~~379~~443			45163,~~414~~978			4044,~~285~~728
Income tax provision	~~409~~2,412			~~391~~509			~~749~~3,161			~~418~~927
Net income	$	13116,~~496~~152		$	283,~~988~~934		$	44160,~~665~~817		$	3943,~~867~~801
Net income per unit:
Basic	$	01.1416		$	0.4305		$	01.4971		$	0.5861
Diluted	$	01.1416		$	0.4305		$	01.4971		$	0.5861
Weighted average units outstanding:
Weighted average common units outstanding:
Basic	9598,~~212~~920			6878,~~196~~493			8992,~~629~~760			6871,~~196~~666
Diluted	9598,~~212~~920			6878,~~196~~493			8992,~~629~~760			6871,~~196~~666

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

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ATHLON HOLDINGS LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

(in thousands)

(unaudited)

Balance at December 31, 2013	$	725,247
Equity-based compensation	917,~~024~~452
Net contributions from Athlon Energy Inc.	~~567~~562,~~606~~246
Net income	44160,~~665~~817
Balance at June 30, 2014	$	1,346,542
Balance at September 30, 2014	$	1,465,762

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

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ATHLON HOLDINGS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six months ended June 30,
	Nine months ended September 30,
	2014			2013
Cash flows from operating activities:
Net income	$	44160,~~665~~817		$	3943,~~867~~801
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization	66116,~~546~~792			3862,~~411~~022
Deferred taxes	~~749~~3,161			~~418~~927
Non-cash derivative loss (gain)	30(32,~~519~~300		)	(613,~~127~~955		)
Equity-based compensation	815,~~267~~732			~~113~~1,799
Other	13,~~955~~308			34,~~979~~756
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	(3246,~~101~~897		)	(1221,~~623~~350		)
Other current assets	~~1,907~~961			~~424~~(155		)
Accounts payable	~~2,825~~(239		)	(~~2,503~~702		)
Intercompany payable	~~404~~514			—
Accrued interest	625,~~503~~546			615,~~898~~968
Revenue payable	1214,~~314~~709			59,~~723~~718
Other current liabilities	1112,~~862~~201			46,~~651~~285
Other assets	(90		)	—
Net cash provided by operating activities	~~156~~274,~~325~~215			79137,~~231~~024
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(~~974~~1,~~732~~365,205		)	(1636,~~482~~533		)
Development of oil and natural gas properties	(~~256~~451,~~057~~360		)	(~~161~~257,~~514~~984		)
Other	(~~830~~1,317		)	(~~336~~486		)
Net cash used in investing activities	(1,~~231~~817,~~619~~882		)	(~~178~~295,~~332~~003		)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs	~~797~~1,~~493~~056,243			~~594~~629,~~647~~627
Payments on long-term debt	(~~160~~183,000		)	(~~427~~505,~~426~~926		)
Net contributions from (distributions to) Athlon Energy Inc.	567,671			(7		)
Net contributions from Athlon Energy Inc.	562,246			295,795
Distributions to Class A limited partners	—			(75,000		)
Other	—			~~563~~1,500
Net cash provided by financing activities	1,~~205~~435,~~164~~489			92345,~~777~~996
Increase (decrease) in cash and cash equivalents	~~129~~(108,~~870~~178		)	(6188,~~324~~017		)
Cash and cash equivalents, beginning of period	113,025			8,871
Cash and cash equivalents, end of period	$	~~242~~4,~~895~~847		$	2196,~~547~~888

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

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1. Formation of the Partnership and Description of Business

Athlon Holdings LP (together with its subsidiaries, “Holdings”), a Delaware limited partnership, 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. Athlon Finance Corp., a Delaware corporation, is a wholly owned subsidiary of Holdings whose sole purpose is to serve as the co-issuer of Holdings’ senior notes. Athlon Holdings GP LLC serves as Holdings’ general partner with no obligations to make capital contributions and no rights to distributions.

On April 26, 2013, Holdings underwent a corporate reorganization and as a result, Holdings became a majority-owned subsidiary of Athlon Energy Inc. (together with its subsidiaries, “Athlon”), a Delaware corporation. 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.

Athlon’s Initial Public Offering

On August 7, 2013, Athlon completed its initial public offering (the “Athlon 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 Athlon 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 12. Related Party Transactions” for additional discussion. All other New Holdings Units are held by Athlon.

Athlon’s 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

Holdings’ consolidated financial statements include the accounts of its wholly 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, Holdings’ financial position as of ~~June~~September 30, 2014, results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2014 and 2013, and cash flows for the ~~six~~nine months ended ~~June~~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.

Certain amounts and disclosures have been condensed and omitted from the unaudited consolidated financial statements pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). Therefore, these unaudited consolidated financial statements should be read in conjunction with Holdings’ audited consolidated financial statements and related notes thereto included in Holdings’ final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act of 1933, as amended, on July 24, 2014.

New Accounting Pronouncements

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

~~services~~Certain toamounts ~~customers~~and indisclosures anhave ~~amount~~been ~~that~~condensed ~~reflects~~and ~~the~~omitted ~~consideration~~from the ~~entity~~unaudited ~~expects~~consolidated tofinancial bestatements ~~entitled~~pursuant to inthe ~~exchange~~rules and ~~for~~regulations ~~those~~of ~~goods~~the orUnited ~~services~~States Securities and ~~(ii) requires~~Exchange ~~expanded~~Commission ~~disclosures regarding~~ (the ~~nature~~“SEC”). Therefore, ~~amount,~~these ~~timing,~~unaudited ~~and~~consolidated ~~certainty~~financial ofstatements ~~revenue~~should ~~and~~be ~~cash~~read ~~flows~~in ~~from~~conjunction ~~contracts~~ with ~~customers. ASU~~Holdings’ ~~2014-09~~audited isconsolidated ~~effective~~financial ~~retrospectively~~statements ~~for annual~~ and ~~interim~~related ~~reporting~~notes ~~periods~~thereto ~~beginning~~included ~~after~~in ~~December 15, 2016,~~Holdings’ ~~with~~final ~~early~~prospectus ~~application~~filed ~~not~~with ~~permitted. Holdings is evaluating~~ the ~~impact,~~SEC ifpursuant ~~any,~~to ~~that~~Rule 424(b)(3) of the ~~adoption~~Securities Act of ~~ASU~~1933, ~~2014-09~~as ~~will~~amended, ~~have~~ on ~~its financial position~~July 24, ~~results of operations, and liquidity~~2014.

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. Holdings 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 Holdings’ unaudited consolidated financial statements.

Note 3. Acquisitions

On June 2, 2014 ~~and June 3~~, ~~2014,~~ Holdings acquired certain oil and natural gas properties and related assets in the ~~Permian~~Midland Basin ~~in West Texas~~ from Hibernia Holdings, LLC (“Hibernia”) ~~and Piedra Energy II, LLC (“Piedra”), respectively,~~ for approximately $~~388~~394.70 million ~~and $290.2 million~~ in cash, ~~respectively~~which ~~(the~~was ~~“Acquisitions”). The Acquisitions were~~ financed with a portion of the net proceeds from debt and equity offerings. Please read “Note 7. Long-Term Debt” and “Note 8. Partners’ 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 Holdings from the date of acquisition. Holdings 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. Holdings incurred approximately $10.27 million of transaction costs related to the ~~Acquisitions~~Hibernia acquisition, which are included in “Acquisition costs” in the accompanying Consolidated Statements of Operations.

~~Based~~On onJune 3, ~~currently~~2014, ~~available~~Holdings ~~information,~~acquired certain oil and natural gas properties and related assets in the ~~estimated~~Midland ~~allocation~~Basin from Piedra Energy II, LLC (“Piedra”) for approximately $292.8 million in cash, which was financed with a portion of the ~~purchase~~net ~~price~~proceeds tofrom ~~the~~debt ~~fair~~and ~~value~~equity offerings. Please read “Note 7. Long-Term Debt” and “Note 8. Partners’ Equity” for additional discussion of these offerings. The operations of these properties have been included in the ~~assets~~accompanying ~~acquired~~Consolidated ~~and~~Statements ~~liabilities~~of ~~assumed~~Operations with those of Holdings from the ~~Acquisitions~~date ~~was~~of asacquisition. Holdings ~~follows~~has asincluded 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. Holdings 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.

	Hibernia		Piedra		Total
	(in thousands)
Evaluated, including wells and related equipment	$	240,745	$	173,041	$	413,786
Unevaluated	148,246		117,242		265,488
Inventory	499		759		1,258
Total assets acquired	389,490		291,042		680,532
Other current liabilities	107		289		396
Asset retirement obligations	706		536		1,242
Total liabilities assumed	813		825		1,638
Fair value of net assets acquired	$	388,677	$	290,217	$	678,894

On August 28, 2014, Holdings 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 Holdings’ credit agreement. The operations of these properties have been included in the accompanying Consolidated Statements of Operations with those of Holdings from the date of acquisition. Holdings 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. Holdings 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.

At June 30, 2014, Holdings was awaiting final close on the 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 Holdings and from the accounting records of Hibernia and Piedra 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.

	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
	(in thousands, except per unit amounts)
Pro forma total revenues	$	150,961	$	74,336	$	277,617	$	138,670
Pro forma net income	$	16,880	$	22,473	$	47,308	$	27,661
Pro forma net income per unit:
Basic	$	0.17	$	0.27	$	0.47	$	0.33
Diluted	$	0.17	$	0.27	$	0.47	$	0.33

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:

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

	June 30,		December 31,
	2014		2013
	(in thousands)
Evaluated leasehold costs	$	912,321	$	448,689
Wells and related equipment - completed	1,111,196		748,900
Wells and related equipment - in process	47,138		46,589
Total evaluated	$	2,070,655	$	1,244,178

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, Holdings 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 Holdings 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.

	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
	(in thousands, except per unit amounts)
Pro forma total revenues	$	171,740	$	116,169	$	471,830	$	271,420
Pro forma net income	$	120,264	$	7,483	$	180,009	$	45,317

Pro forma net income per unit:
Basic	$	1.20	$	0.08	$	1.80	$	0.52
Diluted	$	1.20	$	0.08	$	1.80	$	0.52

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 ~~June~~September 30, 2014, the fair value of Holdings’ 73/8% senior notes due 2021 was approximately $~~547~~542.5 million and the fair value of Holdings’ 6% senior notes due 2022 was approximately $~~674~~698.48 million using open market quotes (“Level 1” input).

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Derivative Policy

Holdings 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 Holdings’ exposure to commodity price decreases, but they can also limit the benefit Holdings might otherwise receive from commodity price increases. Holdings’ risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions, most of which are lenders under Holdings’ credit agreement.

Holdings 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. Holdings 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.

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

Commodity Derivative Contracts

Commodity prices are often subject to significant volatility due to many factors that are beyond Holdings’ 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. Holdings manages oil price risk with swaps, which provide a fixed price for a notional amount of sales volumes. The following table summarizes Holdings’ open commodity derivative contracts as of ~~June~~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

Holdings 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.

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Period	Average Daily Swap Volume	Weighted- Average Swap Price		Net Liability Fair Market Value
	(Bbl)	(per Bbl)		(in thousands)
Q3 2014	9,950	$	92.52
Q4 2014	10,961	92.31
Q3-Q4 2014	10,455	92.41		$	(20,320	)
Q1 2015	9,800	90.90
Q2 2015	9,800	90.90
Q3 2015	4,300	91.11
Q4 2015	4,300	91.11
2015	7,027	90.97		(16,224		)
				$	(36,544	)

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

Counterparty Risk. At June 30, 2014, Holdings did not have a net asset position with any of its 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

Holdings 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, Holdings 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 Holdings. Instead of treating each derivative transaction between the counterparty and Holdings separately, the termination provision of the ISDA Agreement enables the counterparty and Holdings to aggregate all trades under such agreement and treat them as a single agreement. This arrangement is intended to benefit Holdings 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 Holdings’ credit exposure to a given counterparty in the event of close-out. Holdings’ accounting policy is to not offset fair value amounts between different counterparties for derivative instruments in the accompanying Consolidated Balance Sheets.

8Tabular Disclosures of Fair Value Measurements

The following table summarizes the fair value of Holdings’ 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	)

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Tabular Disclosures of Fair Value Measurements

The following table summarizes the fair value of Holdings’ 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 June 30, 2014
Assets
Derivatives - current	$	112		$	(112	)	$	—
Derivatives - noncurrent	318			—			318
Total assets	430			(112		)	318
Liabilities
Derivatives - current	(33,654		)	112			(33,542		)
Derivatives - noncurrent	(3,320		)	—			(3,320		)
Total liabilities	(36,974		)	112			(36,862		)
Net liabilities	$	(36,544	)	$	—		$	(36,544	)
As of December 31, 2013
Assets
Derivatives - current	$	143		$	(143	)	$	—
Derivatives - noncurrent	2,330			—			2,330
Total assets	2,473			(143		)	2,330
Liabilities
Derivatives - current	(8,497		)	143			(8,354		)
Derivatives - noncurrent	—			—			—
Total liabilities	(8,497		)	143			(8,354		)
Net liabilities	$	(6,024	)	$	—		$	(6,024	)

(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 ~~June~~September 30,						~~Six~~Nine months ended ~~June~~September 30,
Derivatives Not Designated as Hedges	Recognized in Income	2014			2013			2014			2013
		(in thousands)
Commodity derivative contracts	Derivative fair value loss (gain)	$	32(58,~~397~~526	)	$	~~(12~~27,~~555~~037	)	$	43(14,~~577~~949	)	$	(521,~~706~~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 HOLDINGS LP

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, Holdings 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. Holdings’ 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 Holdings’ 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. Holdings uses observable inputs ~~in an option pricing valuation model~~ to determine fair value such as: (i) current market and contractual prices for the underlying instruments; (ii) quoted forward prices for oil; (iii) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (iv) appropriate volatilities.

Holdings adjusts the valuations from the valuation model for nonperformance risk. For commodity derivative contracts which are in an asset position, Holdings adds the counterparty’s credit default swap spread to the risk-free rate. If a counterparty does not have a credit default swap spread, Holdings uses other companies with similar credit ratings to determine the applicable spread. For commodity derivative contracts which are in a liability position, Holdings uses the yield on its senior notes less the risk-free rate. All fair values have been adjusted for nonperformance risk resulting in a decrease in the net commodity derivative ~~liability~~asset of approximately $~~630~~56,000 ~~and $39,000~~ as of ~~June~~September 30, 2014 and a decrease in the net commodity derivative liability of approximately $39,000 as of December 31, 2013~~, respectively~~.

The following table sets forth Holdings’ 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 Liability			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
As of June 30, 2014
Oil derivative contracts - swaps	$	(36,544	)	$	—	$	(36,544	)	$	—
As of December 31, 2013
Oil derivative contracts - swaps	$	(6,024	)	$	—	$	(6,024	)	$	—

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 Holdings’ asset retirement obligations for the six months ended June 30, 2014 (in thousands):

Balance at January 1	$	6,855
Liabilities assumed in acquisitions	2,177
Liabilities incurred from new wells	867
Liabilities settled	(103		)
Accretion of discount	417
Revisions of previous estimates	292
Balance at June 30	10,505
Less: current portion	9
Asset retirement obligations - long term	$	10,496

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

The following table sets forth Holdings’ 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	)	$	—

Note 6. Asset Retirement Obligations

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	~~June~~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,~~150~~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, Holdings 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, Holdings 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 Holdings’ option, prior to April 15, 2016, Holdings 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 Holdings 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, which were used to fund a portion of the purchase price of the Acquisitions, to provide additional liquidity for use in Holdings’ drilling program, and for general partnership purposes. Athlon is an unconditional guarantor of the 2022 Notes. Under the indenture, starting on May 1, 2017, Holdings 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, Holdings 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 Holdings’ option, prior to May 1, 2017, Holdings 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, Holdings 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 Holdings 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.11

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

will be triggering events that may require Holdings 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, Holdings 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, Holdings 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 Holdings’ option, prior to May 1, 2017, Holdings 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, Holdings 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 Holdings 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 Holdings’ senior notes contain covenants, including, among other things, covenants that restrict Holdings’ ability to:

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

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

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

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

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

11Credit Agreement

Holdings 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 Holdings from time to time and letters of credit to be issued from time to time for the account of Holdings or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the 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. In addition, obligations under the Credit Agreement are guaranteed by Athlon.

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

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

Credit Agreement

Holdings is a party to an amended and restated credit agreement dated March 19, 2013 (the “Credit Agreement”), which matures on March 19, 2018. The Credit Agreement provides for revolving credit loans to be made to Holdings from time to time and letters of credit to be issued from time to time for the account of Holdings or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the 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. As of June 30, 2014, the borrowing base was $837.5 million and there were no outstanding borrowings and no outstanding letters of credit under the Credit Agreement.

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

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

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

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

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

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

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

· a requirement that Holdings maintain a ratio of consolidated total debt to EBITDAX (as defined in the 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 ~~June~~September 30, 2014, Holdings 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.

12Note 8. Partners’ Equity

Holdings’ Amended and Restated Agreement of Limited Partnership provides that at any time Athlon issues a share of common stock, other than pursuant to an incentive plan or an exchange transaction, the net proceeds or other consideration received by Athlon with respect to such share, if any, shall be concurrently contributed to Holdings and Holdings shall issue to Athlon one New Holdings Unit. Holdings’ Amended and Restated Agreement of Limited Partnership also provides that at any time Athlon issues a share of common stock pursuant to an incentive plan, Athlon is deemed to contribute consideration to Holdings equal to value of the share of common stock issued and Holdings shall issue to Athlon one New Holdings Unit.

In conjunction with the Athlon IPO, Athlon contributed net proceeds of approximately $295.7 million to Holdings and Holdings issued 15,789,474 New Holdings Units to Athlon. In conjunction with Athlon’s public offering in April 2014, Athlon contributed net proceeds of approximately $570.8 million to Holdings and Holdings issued 14,806,250 New Holdings Units to Athlon. In conjunction with the vesting of stock awards, Holdings issued 199,107 New Holdings Units to Athlon during the nine months ended September 30, 2014.

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

~~and~~The isfollowing ~~continuing,~~table ~~lenders~~shows ~~with~~Holdings’ apartnership ~~majority~~interests ofas ~~the aggregate commitments may require Bank~~ of ~~America~~September 30, ~~N.A. to declare all amounts outstanding under the Credit Agreement to be immediately due and payable.~~2014:

Note 8. Partners’ 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, which were used to fund a portion of the purchase price of the Acquisitions, to reduce outstanding indebtedness under the Credit Agreement, to provide additional liquidity for use in Holdings’ drilling program, and for general partnership purposes. Upon consummation of the offering, Athlon’s ownership percentage of Holdings increased.

The following table shows Holdings’ partnership interests as of June 30, 2014:

		Partnership
		Interest
Athlon Holdings GP LLC	General Partner	0.0	%
Athlon Energy Inc.	Limited Partner	98.1	%
Management team and certain employees	Limited Partner	1.9	%

Note 9. Earnings Per Unit

Prior to the consummation of the Athlon IPO, Holdings had 989,508 outstanding limited partner units. In conjunction with the closing of the Athlon 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 Athlon 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 limited partner units increased from 989,508 units to 68,195,178 units. The one-to-one conversion of Holdings’ interests in April 2013 to 989,508 limited partner units is akin to a stock split and has been treated as such in Holdings’ earnings per unit (“EPU”) calculations. Accordingly, Holdings assumes that 68,195,178 limited partner units were outstanding during periods prior to the Athlon IPO for purposes of calculating EPU.

Holdings’ Amended and Restated Agreement of Limited Partnership provides that at any time Athlon issues a share of common stock, other than pursuant to an incentive plan or an exchange transaction, the net proceeds or other consideration received by Athlon with respect to such share, if any, shall be concurrently contributed to Holdings and Holdings shall issue to Athlon one New Holdings Unit. In conjunction with the Athlon IPO, Athlon contributed net proceeds of approximately $295.7 million to Holdings and Holdings issued 15,789,474 New Holdings Units to Athlon. In conjunction with Athlon’s public offering in April 2014, Athlon contributed net proceeds of approximately $570.8 million to Holdings and Holdings issued 14,806,250 New Holdings Units to Athlon.

As a result of the aforementioned provision in Holdings’ Amended and Restated Agreement of Limited Partnership, Athlon’s unvested stock awards are dilutive to Holdings’ EPU calculations. The following table reflects the allocation of net income to unitholders and EPU computations for the periods indicated:

	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(in thousands, except per unit amounts)
Basic EPU
Numerator:
Undistributed net income attributable to unitholders	$	116,152		$	3,934		$	160,817		$	43,801
Participation rights of unvested stock awards in undistributed earnings	(1,780		)	(9		)	(1,819		)	(9		)
Basic undistributed net income attributable to unitholders	$	114,372		$	3,925		$	158,998		$	43,792
Denominator:
Basic weighted average units outstanding	98,920			78,493			92,760			71,666
Basic EPU attributable to unitholders	$	1.16		$	0.05		$	1.71		$	0.61

Diluted EPU
Numerator:
Undistributed net income attributable to unitholders	$	116,152		$	3,934		$	160,817		$	43,801
Participation rights of unvested stock awards in undistributed earnings	(1,780		)	(9		)	(1,819		)	(9		)
Diluted undistributed net income attributable to unitholders	$	114,372		$	3,925		$	158,998		$	43,792
Denominator:
Diluted weighted average units outstanding	98,920			78,493			92,760			71,666
Diluted EPU attributable to unitholders	$	1.16		$	0.05		$	1.71		$	0.61

Note 10. 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. Athlon’s Compensation Committee will administer the Plan unless its 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.

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

	Three months ended June 30,					Six months ended June 30,
	2014			2013		2014			2013
	(in thousands, except per unit amounts)
Basic EPU
Numerator:
Undistributed net income attributable to unitholders	$	13,496		$	28,988	$	44,665		$	39,867
Participation rights of unvested stock awards in undistributed earnings	(138		)	—		(435		)	—
Basic undistributed net income attributable to unitholders	$	13,358		$	28,988	$	44,230		$	39,867
Denominator:
Basic weighted average units outstanding	95,212			68,196		89,629			68,196
Basic EPU attributable to unitholders	$	0.14		$	0.43	$	0.49		$	0.58
Diluted EPU
Numerator:
Undistributed net income attributable to unitholders	$	13,496		$	28,988	$	44,665		$	39,867
Participation rights of unvested stock awards in undistributed earnings	(138		)	—		(435		)	—
Diluted undistributed net income attributable to unitholders	$	13,358		$	28,988	$	44,230		$	39,867
Denominator:
Diluted weighted average units outstanding	95,212			68,196		89,629			68,196
Diluted EPU attributable to unitholders	$	0.14		$	0.43	$	0.49		$	0.58

(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 Athlon’s 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:

~~Note~~· shares ~~10. Incentive~~subject ~~Stock~~to ~~Plans~~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

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 least of (i) 12,000,000 shares, (ii) 4% of the shares outstanding (on an as-converted basis) on the final day of the immediately preceding calendar year, and (iii) such smaller number of shares as determined by Athlon’s 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 ~~June~~September 30, 2014, there were 109,~~801~~815,~~805~~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 Athlon’s Board of Directors or Compensation Committee from time to time, as part of their compensation decision-making processes, provided, however, that the Plan does not permit awards having a grant date fair value in excess of $700,000 to be granted to Athlon’s non-employee directors in any year.

During the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2014 and 2013, Holdings recorded non-cash ~~stock~~equity-based compensation expense related to the Plan of $415.67 million and $80.35 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 ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2014, ~~Holdings capitalized $0.5 million~~ and ~~$0.8 million~~2013, ~~respectively,~~Holdings ofcapitalized non-cash ~~stock~~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.

14Stock 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

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

~~Stock~~partners ~~awards~~exchanged ~~are~~their ~~scheduled~~interests for shares of Athlon’s common stock subject to ~~vest~~the ~~over~~same ~~three~~conditions ~~years~~and vesting terms. ~~Certain~~Upon ~~awards~~the ~~granted~~consummation toof the Athlon IPO on August 1, 2013, the remaining unvested common stock awards, which were formerly Holdings’s ~~management~~Class B ~~team~~interests, ~~vest~~vested ~~subject~~and toHoldings ~~the~~recognized ~~relative~~non-cash ~~performance~~equity-based compensation expense of ~~Athlon’s~~approximately ~~common~~$1.2 ~~stock~~million, which was allocated to ~~that~~lease ofoperating aexpense ~~designated~~and ~~peer~~general ~~group. The~~and ~~following~~administrative ~~table~~expenses ~~summarizes~~in the ~~changes~~accompanying inConsolidated ~~Athlon’s~~Statements ~~unvested~~of ~~stock~~Operations ~~awards~~based ~~for~~on the ~~six~~allocation ~~months~~of ~~ended~~the ~~June 30~~respective employees’ compensation, ~~2014~~and ~~(presented~~capitalized atnon-cash equity-based compensation expense of $0.4 million as a component of “Evaluated, including wells and related equipment” in the ~~target~~accompanying ~~level):~~Consolidated Balance Sheets.

			Weighted -
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1	638,913		$	34.88
Granted	330,422		37.70
Vested	—		—
Forfeited	(11,754	)	30.97
Outstanding at June 30	957,581		35.90

During the nine months ended September 30, 2013, Holdings 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, Holdings capitalized non-cash equity-based compensation expense related to Class B interests of $0.4 million as a component of “Evaluated, including wells and related equipment” in the accompanying Consolidated Balance Sheets.

As of June 30, 2014, there were 957,581 unvested stock awards, 328,911 of which were granted during 2014, in which the vesting is dependent only on the passage of time and continued employment. Additionally, as of June 30, 2014, there were 227,500 unvested stock awards, none 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.

None of Athlon’s unvested stock awards are subject to variable accounting. As of June 30, 2014, Athlon had approximately $18.6 million of total unrecognized compensation cost related to unvested stock awards, which is expected to be recognized over a weighted-average period of approximately 2.4 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 Partnership 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. During the three and six months ended June 30, 2013, Holdings recorded approximately $65,000 and $113,000, respectively, of non-cash equity-based compensation expense related to Class B interests, which was allocated to lease operating expense and general and administrative expenses in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ compensation. During the three and six months ended June 30, 2013, Holdings capitalized approximately $17,000 and $42,000, respectively, of non-cash equity-based compensation expense related to Class B interests as a component of “Evaluated, including wells and related equipment” in the accompanying Consolidated Balance Sheets.

Note 11. Commitments and Contingencies

From time to time, Holdings 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 Holdings’ business, financial position, results of operations, or liquidity.

Additionally, Holdings 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 12. Related Party Transactions

Services Agreement

Holdings was a party to a Services Agreement, ~~dated August 23, 2010,~~ 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 ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2013, Holdings incurred ~~approximately~~ $~~95,000~~0.5 ~~and~~million ~~$500,000, respectively,~~ 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 Athlon IPO, the Services Agreement was terminated 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.

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

accompanying Consolidated Statements of Operations. Upon the consummation of the Athlon IPO, the Services Agreement was terminated.

Exchange Agreement

Upon the consummation of the Athlon IPO, Holdings entered into an exchange agreement (the “Exchange Agreement”) with its management team and certain employees who hold New Holdings Units. Under the ~~exchange~~Exchange ~~agreement~~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 Athlon IPO, Holdings 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 ~~unitholders~~TRA ofHolders ~~Holdings~~ of 85% of the amount of the tax benefits, if any, that Athlon isactually ~~deemed~~realizes ~~to realize~~ as a result of increases in tax basis and certain other tax benefits related to exchanges of New Holdings Units pursuant to the ~~exchange~~Exchange ~~agreement~~Agreement, including tax benefits attributable to payments under the ~~tax receivable agreement~~TRA. These payment obligations are obligations of Athlon and not of Holdings. For purposes of the ~~tax receivable agreement~~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 tax receivable agreement.

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

Participation of Apollo Global Securities, LLC in Debt and Equity Offerings

Apollo Global Securities, LLC is an affiliate of the Apollo Funds and received a portion of the gross spread as an initial purchaser of the 2022 Notes of $0.5 million. Apollo Global Securities, LLC 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.

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ATHLON HOLDINGS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

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.

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 Athlon IPO and received a portion of the discounts and commissions paid to the underwriters of approximately $0.9 million.

Note 13. Subsequent Events

~~Subsequent~~In ~~to June~~November ~~30,~~ 2014, ~~Holdings~~lenders ~~entered~~under ~~into~~the ~~additional~~Credit ~~oil~~Agreement ~~swaps. The~~completed ~~following~~their ~~table~~redetermination ~~summarizes~~of ~~Holdings’~~the ~~open~~borrowing ~~commodity~~base ~~derivative~~resulting ~~contracts~~in asan ofincrease ~~August 21,~~from ~~2014:~~$837.5 million to $1.0 billion.

Period	Average Daily Swap Volume	Weighted- Average Swap Price
	(Bbl)	(per Bbl)
Q3 2014	9,950	$	92.52
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

Subsequent to June 30, 2014, Holdings entered into purchase and sale agreements with multiple third parties to acquire certain oil and natural gas properties and related assets in the Midland Basin for a purchase price of $382 million, in the aggregate, subject to customary purchase price adjustments. These acquisitions are expected to close during the third quarter of 2014, subject to customary closing conditions.

Table of Contents

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes in “Item 1. Financial Statements”. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in these forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under law. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under “Cautionary Note Regarding Forward-Looking Information”, ~~and~~ “Risk Factors”, and elsewhere in our final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act on July 24, 2014.

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.

Athlon’s Initial Public Offering

On August 7, 2013, Athlon Energy Inc. (“Athlon”) completed its initial public offering (the “Athlon IPO”) of 15,789,474 shares of 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 Athlon IPO, our limited partnership agreement was amended and restated to, among other things, modify our capital structure by replacing our different classes of interests with a single new class of units, the “New Holdings Units”. Our 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~~Exchange ~~agreement~~Agreement) they have the right to 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. All other New Holdings Units are held by Athlon.

Athlon’s Merger with Encana

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 ~~second~~third quarter of 2014:

· Our oil, natural gas, and NGLs revenues increased 109% to $136.5 million in the second quarter of 2014 as compared to $65.2 million in the second quarter of 2013.

· Our average daily production volumes increased 96% to 21,901 BOE/D in the second quarter of 2014 as compared to 11,183 BOE/D in the second quarter of 2013. Oil and NGLs represented approximately 82% of our total production volumes in the second quarter of 2014.

· Our average realized oil price increased 2% to $93.91 per Bbl in the second quarter of 2014 as compared to $91.80 per Bbl in the second quarter of 2013, our average realized natural gas price increased 9% to $4.07 per Mcf in the second quarter of 2014 as compared to $3.72 per Mcf in the second quarter of 2013, and our average realized NGL price increased 19% to $32.43 per Bbl in the second quarter of 2014 as compared to $27.27 per Bbl in the second quarter of 2013.

· Our production margin increased 113% to $113.1 million in the second quarter of 2014 as compared to $53.1 million in the second quarter of 2013. Total wellhead revenues per BOE increased 7% and total production expenses per BOE decreased 1%. On a per BOE basis, our production margin increased 9% to $56.76 per BOE in the second quarter of 2014 as compared to $52.16 per BOE for the second quarter of 2013.

· We invested $1.1 billion in oil and natural gas activities, of which $172.7 million was invested in development and exploration activities and $883.3 million was invested in acquisitions of oil and natural gas properties.

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· WeOur ~~completed the acquisitions of certain~~ oil, ~~and~~ natural gas, ~~properties~~ and ~~related~~NGLs ~~assets~~revenues inincreased ~~the~~88% ~~Midland~~to ~~Basin~~$166.0 million (in the ~~“Acquisitions”)~~third ~~for~~quarter aof ~~combined~~2014 ~~purchase~~as ~~price~~compared ofto ~~approximately~~ $~~877~~88.1 4 million, ~~subject~~in tothe ~~post-closing~~third ~~adjustments~~quarter of 2013.

· 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.

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Results of Operations

Comparison of Quarter Ended ~~June~~September 30, 2014 to Quarter Ended ~~June~~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 June 30,				Increase / (Decrease)
	Three months ended September 30,				Increase / (Decrease)
	2014		2013		$			%
Revenues (in thousands):
Oil	$	~~114~~139,~~137~~925	$	5475,~~609~~666	$	5964,~~528~~259		~~109~~85	%
Natural gas	89,~~687~~795		4,~~363~~164		45,~~324~~631			99135	%
NGLs	1316,~~686~~321		68,~~193~~595		7,~~493~~726			~~121~~90	%
Total revenues	$	~~136~~166,~~510~~041	$	6588,~~165~~425	$	7177,~~345~~616		~~109~~88	%
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	9386.9141	$	91104.8021	$	2(17.1180	)	2-17	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	8683.9167	$	9194.0339	$	(410.1272	)	-511	%
Natural gas ($/Mcf)	$	43.0758	$	3.7228	$	0.3530		9	%
NGLs ($/Bbl)	$	3229.4360	$	2733.2776	$	5(4.16	)	19-12	%
Combined ($/BOE) (before impact of cash settled derivatives)	$	6863.4920	$	6474.0416	$	4(10.4596	)	7-15	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	6461.2351	$	6368.5918	$	0(6.6467	)	1-10	%
Total production volumes:
Oil (MBbls)	1,~~215~~619		~~595~~726		~~620~~893			~~104~~123	%
Natural gas (MMcf)	2,~~134~~739		1,~~174~~270		~~960~~1,469			82116	%
NGLs (MBbls)	~~422~~551		~~227~~255		~~195~~296			86116	%
Combined (MBOE)	12,~~993~~627		1,~~018~~192		~~975~~1,435			96120	%
Average daily production volumes:
Oil (Bbls/D)	1317,~~356~~601		67,~~537~~893		69,~~819~~708			~~104~~123	%
Natural gas (Mcf/D)	2329,~~453~~769		1213,~~897~~804		1015,~~556~~965			82116	%
NGLs (Bbls/D)	45,~~637~~994		2,~~496~~767		23,~~141~~227			86117	%
Combined (BOE/D)	2128,~~901~~556		1112,~~183~~960		1015,~~718~~596			96120	%

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		%

~~Table~~Our average oil differential to NYMEX WTI widened to $10.80 per Bbl for the third quarter of ~~Contents~~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.

	Three months ended June 30,
	2014			2013
Average realized oil price ($/Bbl)	$	93.91		$	91.80
Average NYMEX WTI ($/Bbl)	$	102.98		$	94.23
Differential to NYMEX WTI	$	(9.07	)	$	(2.43	)
Average realized oil price to NYMEX WTI percentage	91		%	97		%
Average realized natural gas price ($/Mcf)	$	4.07		$	3.72
Average NYMEX Henry Hub ($/Mcf)	$	4.67		$	4.09
Differential to NYMEX Henry Hub	$	(0.60	)	$	(0.37	)
Average realized natural gas price to NYMEX Henry Hub percentage	87		%	91		%

Our average oil differential to NYMEX WTI widened to $9.07 per Bbl for the second quarter of 2014 as compared to $2.43 per Bbl for the second 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 $0.60 per Mcf for the second quarter of 2014 as compared to $0.37 per Mcf for the second quarter of 2013, primarily due to a temporary increase in transportation fees to move our natural gas production out of the Midland Basin.

Oil revenues increased 109% to $114.1 million in the second quarter of 2014 from $54.6 million in the second quarter of 2013 as a result of an increase in our oil production volumes of 620 MBbls and a $2.11 per Bbl increase in our average realized oil price. Our higher oil production increased oil revenues by $57.0 million and was primarily the result of our development program and additional production from the Acquisitions. Our higher average realized oil price increased oil revenues by $2.6 million and was primarily due to a higher average NYMEX price, which increased to $102.98 per Bbl in the second quarter of 2014 from $94.23 per Bbl in the second quarter of 2013, partially offset by the widening of our oil differentials as previously discussed.

Natural gas revenues increased 99% to $8.7 million in the second quarter of 2014 from $4.4 million in the second quarter of 2013 as a result of an increase in our natural gas production volumes of 960 MMcf and a $0.35 per Mcf increase in our average realized natural gas price. Our higher natural gas production increased natural gas revenues by $3.6 million and was primarily the result of our development program and additional production from the Acquisitions, partially offset by flaring a portion of our natural gas production due to temporary delays and constraints related to third-party gathering systems. Our higher average realized natural gas price increased natural gas revenues by $0.7 million and was primarily due to a higher average NYMEX price, which increased to $4.67 per Mcf in the second quarter of 2014 from $4.09 per Mcf in the second quarter of 2013, partially offset by the widening of our natural gas differentials as previously discussed.

NGL revenues increased 121% to $13.7 million in the second quarter of 2014 from $6.2 million in the second quarter of 2013 as a result of an increase in our NGL production volumes of 195 MBbls and a $5.16 per Bbl increase in our average realized NGL price. Our higher NGL production increased NGL revenues by $5.3 million and was primarily the result of our development program and additional production from the Acquisitions, partially offset by flaring as described above. Our higher average realized NGL price increased NGL revenues by $2.2 million.

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~~Expenses~~Oil revenues increased 85% to $139. ~~The~~9 ~~following~~million ~~table~~in ~~summarizes~~the third quarter of 2014 from $75.7 million in the third quarter of 2013 as a result of an increase in our ~~expenses~~oil ~~for~~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 ~~periods~~result ~~indicated:~~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.

	Three months ended June 30,					Increase / (Decrease)
	2014		2013			$			%
Expenses (in thousands):
Production:
Lease operating (a)	$	14,713	$	7,775		$	6,938		89	%
Production, severance, and ad valorem taxes	8,661		4,312			4,349			101	%
Total production expenses	23,374		12,087			11,287			93	%
Other:
Depletion, depreciation, and amortization	38,470		20,358			18,112			89	%
General and administrative (b)	13,430		3,558			9,872			277	%
Acquisition costs	1,207		94			1,113			1184	%
Derivative fair value loss (gain)	32,397		(12,555		)	44,952			-358	%
Accretion of discount on asset retirement obligations	222		162			60			37	%
Total operating	109,100		23,704			85,396			360	%
Interest	13,528		12,082			1,446			12	%
Income tax provision	409		391			18			5	%
Total expenses	$	123,037	$	36,177		$	86,860		240	%
Expenses (per BOE):
Production:
Lease operating (a)	$	7.38	$	7.64		$	(0.26	)	-3	%
Production, severance, and ad valorem taxes	4.35		4.24			0.11			3	%
Total production expenses	11.73		11.88			(0.15		)	-1	%
Other:
Depletion, depreciation, and amortization	19.30		20.01			(0.71		)	-4	%
General and administrative (b)	6.74		3.50			3.24			93	%
Acquisition costs	0.61		0.10			0.51			510	%
Derivative fair value loss (gain)	16.26		(12.34		)	28.60			-232	%
Accretion of discount on asset retirement obligations	0.11		0.16			(0.05		)	-31	%
Total operating	54.75		23.31			31.44			135	%
Interest	6.79		11.87			(5.08		)	-43	%
Income tax provision	0.21		0.38			(0.17		)	-45	%
Total expenses	$	61.75	$	35.56		$	26.19		74	%

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.

~~(a) For~~NGL revenues increased 90% to $16.3 million in the ~~second~~third quarter of 2014, ~~includes~~from ~~non-cash~~$8.6 ~~LOE~~million ~~for~~in ~~oil~~the ~~inventory~~third ~~assumed~~quarter of 2013 as a result of an increase in ~~acquisitions~~our NGL production volumes of ~~$1.6~~296 ~~million~~MBbls, (partially offset by a $04.8216 per ~~BOE)~~Bbl ~~and~~decrease ~~non-cash~~in ~~equity-based~~our ~~compensation~~average ofrealized $0NGL price.4 Our ~~million~~higher (NGL production increased NGL revenues by $010.210 ~~per~~million ~~BOE). For~~and ~~the~~was ~~second~~primarily ~~quarter~~the result of ~~2013~~our development program, ~~includes~~additional ~~non-cash~~production ~~equity-based~~from ~~compensation~~our of2014 $8acquisitions,~~000~~ ~~($0~~and a reduction in flaring as described above.01 Our ~~per~~lower ~~BOE)~~average realized NGL price decreased NGL revenues by $2.3 million.

(b) For the second quarter of 2014, includes non-cash equity-based compensation of $4.2 million ($2.12 per BOE). For the second quarter of 2013, includes corporate reorganization costs of $0.5 million ($0.50 per BOE), advisory fees of $95,000 ($0.09 per BOE), and non-cash equity-based compensation of $57,000 ($0.06 per BOE).

Production expenses. LOE increased 89% to $14.7 million in the second quarter of 2014 from $7.8 million in the second quarter of 2013 as a result of an increase in production volumes as previously discussed, which contributed $7.4 million of additional LOE, partially offset by a $0.26 decrease in the average per BOE rate, which would have reduced LOE by $0.5 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 101% to $8.7 million in the second quarter of 2014 from $4.3 million in the second quarter 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 6.3% in the second quarter of 2014 as compared to 6.6% in the second quarter 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.

Depreciation, depletion, and amortization (“DD&A”). DD&A expense increased 89% to $38.5 million in the second quarter of 2014 from $20.4 million in the second quarter of 2013 primarily due to an increase in production volumes as previously discussed and

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anExpenses. The ~~increase~~following intable ~~our~~summarizes ~~asset base subject to amortization as a result of~~ our ~~drilling~~expenses ~~activity~~for ~~and additional properties added in~~ the ~~Acquisitions.~~periods indicated:

General and administrative expense (“G&A”). G&A expense, excluding non-cash equity-based compensation, increased 163% to $9.2 million in the second quarter of 2014 from $3.5 million in the second quarter of 2013 primarily due to 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. Non-cash equity-based compensation allocated to G&A expense increased to $4.2 million in the second quarter of 2014 from $57,000 in the second quarter of 2013 primarily due to stock awards granted to employees as part of our incentive program.

	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)	14,306			6,454		7,852			122	%
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	35,011			73,973		(38,962		)	-53	%
Interest	12,502			10,039		2,463			25	%
Income tax provision	2,412			509		1,903			374	%
Total expenses	$	49,925		$	84,521	$	(34,596	)	-41	%

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)	5.45			5.41		0.04			1	%
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	13.33			62.04		(48.71		)	-79	%
Interest	4.76			8.42		(3.66		)	-43	%
Income tax provision	0.92			0.43		0.49			114	%
Total expenses	$	19.01		$	70.89	$	(51.88	)	-73	%

~~Derivative fair value loss~~ (~~gain~~a)~~. During~~ For the ~~second~~third quarter of 2014, weincludes ~~recorded~~non-cash aequity-based compensation of $320.47 million ~~derivative fair value loss as compared to a~~ ($120.626 ~~million~~per ~~derivative~~BOE) ~~fair~~and ~~value~~non-cash ~~gain~~LOE infor ~~the~~oil ~~second~~inventory ~~quarter~~assumed ~~of 2013. Since we do not use hedge accounting, changes~~ in ~~fair~~acquisitions ~~value~~ of ~~our~~$0.5 ~~derivatives~~million ~~are~~($0.19 ~~recognized~~per ~~as gains and losses in the current period~~BOE). ~~Included~~For inthe ~~these~~third ~~amounts~~quarter ~~were~~of ~~total~~2013, includes non-cash ~~settlements~~equity-based ~~paid~~compensation ~~on derivatives adjusted for recovered premiums~~ of $80.52 million ~~during the second quarter of 2014 as compared to~~ ($0.516 ~~million~~per ~~during the second quarter of 2013~~BOE).

~~Interest~~(b) For ~~expense. Interest expense increased 12% to $13.5 million in~~ the ~~second~~third quarter of 2014, ~~from~~includes ~~$12.1~~non-cash ~~million~~equity-based incompensation ~~the second quarter~~ of ~~2013~~$6.8 ~~due~~million to($2.58 ~~higher~~per ~~long-term~~BOE) ~~debt balances~~ and ~~higher~~Encana ~~borrowing~~merger costs ~~in the second quarter~~ of ~~2014~~$1.8 ~~when~~million ~~compared~~($0.68 toper BOE). For the ~~second~~third quarter of 2013~~. Our~~, ~~weighted~~includes non-~~average~~recurring ~~total~~Athlon ~~debt~~IPO ~~increased~~costs toof $~~970~~2.1 million ~~for~~($1.77 ~~the~~per ~~second~~BOE), ~~quarter~~non-cash ofequity-based ~~2014~~compensation asof ~~compared to~~ $~~517.~~0.5 million ~~for~~($0.40 ~~the~~per ~~second quarter of 2013~~BOE), ~~primarily due to (i) funding requirements to develop our oil~~ and ~~natural~~corporate ~~gas~~reorganization ~~properties~~costs ~~that~~of ~~are~~$0.2 ~~not~~million ~~covered by our operating cash flows and~~ (~~ii) funding~~$0.13 ofper ~~the Acquisitions~~BOE).

~~Our~~Production ~~weighted-average~~expenses. LOE ~~interest~~increased ~~rate,~~90% ~~net of capitalized interest, decreased~~ to 6$16.2%7 ~~for~~million in the ~~second~~third quarter of 2014 asfrom ~~compared to 9~~$8.3%8 ~~for~~million in the ~~second~~third quarter of 2013, ~~primarily~~as ~~due~~a toresult ~~the~~of ~~write~~an ~~off~~increase ofin ~~unamortized~~production ~~debt~~volumes ~~issuance~~as ~~costs~~previously indiscussed, ~~the~~which ~~second~~contributed ~~quarter~~$10.5 million of ~~2013~~additional LOE, partially offset by ~~the~~a ~~issuance~~$1.00 ofdecrease ~~our~~in ~~73/8%~~the ~~senior~~average ~~notes~~per inBOE ~~April 2013~~rate, awhich ~~portion~~would ofhave ~~the~~reduced ~~net~~LOE ~~proceeds~~by ~~from~~$2.6 ~~which~~million ~~were~~if ~~used~~production tohad ~~reduce~~been ~~outstanding~~unchanged. The ~~borrowings~~decrease ~~under~~in our ~~credit~~average ~~agreement~~LOE ~~that~~per ~~were~~BOE ~~subject~~rate was attributable to ~~lower~~our ~~interest~~close ~~rates~~control ~~than~~of well servicing costs and leverage of our ~~senior~~centralized ~~notes~~service facilities and water handling systems.

~~The~~Production, ~~following~~severance, ~~table~~and ~~provides~~ad valorem taxes increased 112% to $11.6 million in the ~~components~~third quarter of ~~our~~2014 ~~interest~~from ~~expense~~$5.5 ~~for~~million in the ~~periods~~third ~~indicated:~~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.

	Three months ended June 30,						Increase /
	2014			2013			(Decrease)
	(in thousands)
Credit agreement	$	714		$	687		$	27
73/8% senior notes	9,244			7,708			1,536
6% senior notes	6,515			—			6,515
Former second lien term loan	—			427			(427		)
Write off of debt issuance costs	—			2,838			(2,838		)
Amortization of debt issuance costs	789			491			298
Less: interest capitalized	(3,734		)	(69		)	(3,665		)
Total	$	13,528		$	12,082		$	1,446

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~~Comparison~~Depreciation, ofdepletion, ~~Six~~and ~~Months~~amortization ~~Ended~~(“DD&A”). DD&A ~~June 30,~~expense ~~2014~~increased 113% to ~~Six~~$50.2 ~~Months~~million ~~Ended~~in ~~June 30,~~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.

~~Revenues~~General and administrative (“G&A”). ~~The~~ G&A ~~following~~expense, ~~table~~excluding ~~provides~~non-cash equity-based compensation, increased 26% to $7.5 million in the ~~components~~third quarter of ~~our~~2014 ~~revenues~~from ~~for~~$6.0 million in the ~~periods~~third ~~indicated~~quarter of 2013 primarily due to (i) higher payroll and payroll-related costs, asincluding ~~well~~mid-year performance bonuses, as ~~each~~we ~~period~~continue to add employees in order to accommodate our growing drilling program and (ii) $1.8 million of costs related to Athlon’s ~~respective~~pending ~~production~~merger ~~volumes~~with ~~and~~Encana, ~~average~~partially ~~prices:~~offset by $2.1 million of non-recurring Athlon IPO costs in the third quarter of 2013. Non-cash equity-based compensation allocated to G&A expense increased to $6.8 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.

	Six months ended June 30,				Increase / (Decrease)
	2014		2013		$			%
Revenues (in thousands):
Oil	$	201,219	$	100,268	$	100,951		101	%
Natural gas	16,112		7,730		8,382			108	%
NGLs	24,848		11,913		12,935			109	%
Total revenues	$	242,179	$	119,911	$	122,268		102	%
Average realized prices:
Oil ($/Bbl) (before impact of cash settled derivatives)	$	93.71	$	88.19	$	5.52		6	%
Oil ($/Bbl) (after impact of cash settled derivatives)	$	87.50	$	87.51	$	(0.01	)	0	%
Natural gas ($/Mcf)	$	4.26	$	3.51	$	0.75		21	%
NGLs ($/Bbl)	$	33.38	$	29.08	$	4.30		15	%
Combined ($/BOE) (before impact of cash settled derivatives)	$	68.76	$	62.65	$	6.11		10	%
Combined ($/BOE) (after impact of cash settled derivatives)	$	64.98	$	62.25	$	2.73		4	%
Total production volumes:
Oil (MBbls)	2,147		1,137		1,010			89	%
Natural gas (MMcf)	3,781		2,204		1,577			72	%
NGLs (MBbls)	744		410		334			81	%
Combined (MBOE)	3,522		1,914		1,608			84	%
Average daily production volumes:
Oil (Bbls/D)	11,863		6,281		5,582			89	%
Natural gas (Mcf/D)	20,891		12,176		8,715			72	%
NGLs (Bbls/D)	4,113		2,263		1,850			82	%
Combined (BOE/D)	19,458		10,574		8,884			84	%

Contract termination fee. We were a party to a Services Agreement which required us to compensate Apollo for consulting and advisory services. Upon the consummation of the Athlon IPO, we terminated the Services Agreement and, in connection with the termination, we 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.

~~The~~Derivative ~~following~~fair ~~table~~value ~~shows~~loss (gain). During the ~~relationship~~third ~~between~~quarter ~~our~~of ~~average~~2014, ~~oil~~we ~~and~~recorded ~~natural~~a ~~gas~~$58.5 ~~realized~~million ~~prices~~derivative fair value gain as compared to a ~~percentage~~$27.0 million derivative fair value loss in the third quarter of ~~average~~2013. Since ~~NYMEX~~we ~~prices~~do ~~for~~not use hedge accounting, changes in fair value of our derivatives are recognized as gains and losses in the ~~periods~~current ~~indicated~~period. ~~Management~~ Included ~~uses~~in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums during the ~~realized~~third ~~price~~quarter toof ~~NYMEX~~2014 ~~margin~~of ~~analysis~~$4.4 tomillion ~~analyze~~as ~~trends~~compared into ~~our~~$7.1 ~~oil~~million ~~and~~during ~~natural~~the ~~gas~~third ~~revenues~~quarter of 2013.

	Six months ended June 30,
	2014			2013
Average realized oil price ($/Bbl)	$	93.71		$	88.19
Average NYMEX WTI ($/Bbl)	$	100.81		$	94.28
Differential to NYMEX WTI	$	(7.10	)	$	(6.09	)
Average realized oil price to NYMEX WTI percentage	93		%	94		%
Average realized natural gas price ($/Mcf)	$	4.26		$	3.51
Average NYMEX Henry Hub ($/Mcf)	$	4.79		$	3.72
Differential to NYMEX Henry Hub	$	(0.53	)	$	(0.21	)
Average realized natural gas price to NYMEX Henry Hub percentage	89		%	94		%

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 ~~oil~~interest ~~differential~~rate, tobefore ~~NYMEX~~capitalized ~~WTI~~interest, ~~widened~~decreased to $76.108% ~~per Bbl~~ for the ~~first~~third ~~six~~quarter ~~months~~ of 2014 as compared to $67.095% ~~per Bbl~~ for the ~~first~~third ~~six~~quarter ~~months~~ of 2013, primarily due to ~~intermittent capacity constraints between~~ the ~~Midland~~issuance ~~Basin, Cushing, Oklahoma, and Gulf Coast refineries. Our average natural gas differential to NYMEX Henry Hub widened to $0.53 per Mcf for the first six months~~ of ~~2014~~our as6% ~~compared~~senior tonotes ~~$0.21 per Mcf for the first six months of 2013, primarily due to a temporary increase~~ in ~~transportation fees to move our natural gas production out of the Midland Basin~~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

Table of Contents

~~Oil~~Comparison ~~revenues increased 101% to $201.2 million in the first six months~~ of ~~2014~~Nine ~~from~~Months ~~$100.3~~Ended ~~million in the first six months of 2013 as a result of an increase in our oil production volumes of 1~~September 30,~~010~~ ~~MBbls~~2014 and a $5.52 per Bbl increase in our average realized oil price. Our higher oil production increased oil revenues by $89.1 million and was primarily the result of our development program and additional production from the Acquisitions. Our higher average realized oil price increased oil revenues by $11.9 million and was primarily due to aNine ~~higher~~Months ~~average~~Ended ~~NYMEX price~~September 30, ~~which increased to $100.81 per Bbl in the first six months of 2014 from $94.28 per Bbl in the first six months of~~ 2013~~, partially offset by the widening of our oil differentials as previously discussed.~~

~~Natural gas revenues increased 108% to $16~~Revenues.1 The ~~million~~following intable ~~the~~provides ~~first six months of 2014 from $7.7 million in~~ the ~~first~~components ~~six months~~ of ~~2013 as a result of an increase in~~ our ~~natural gas production volumes of 1,577 MMcf and a $0.75 per Mcf increase in our average realized natural gas price. Our higher natural gas production increased natural gas~~ revenues byfor ~~$5.5 million and was primarily~~ the ~~result~~periods ~~of our development program and additional production from the Acquisitions~~indicated, ~~partially~~as ~~offset~~well byas ~~flaring~~each aperiod’s ~~portion~~respective ~~of our natural gas~~ production ~~due~~volumes ~~to temporary delays~~ and ~~constraints related to third-party gathering systems. Our higher~~ average realized natural gas price increased natural gas revenues by $2.8 million and was primarily due to a higher average NYMEX price, which increased to $4.79 per Mcf in the first six months of 2014 from $3.72 per Mcf in the first six months of 2013, partially offset by the widening of our natural gas differentials as previously discussed.prices:

NGL revenues increased 109% to $24.8 million in the first six months of 2014 from $11.9 million in the first six months of 2013 as a result of an increase in our NGL production volumes of 334 MBbls and a $4.30 per Bbl increase in our average realized NGL price. Our higher NGL production increased NGL revenues by $9.7 million and was primarily the result of our development program and additional production from the Acquisitions, partially offset by flaring as described above. Our higher average realized NGL price increased NGL revenues by $3.2 million.

	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

Table of Contents

~~Expenses~~average realized oil price. ~~The~~ Our ~~following~~higher ~~table~~oil ~~summarizes~~production increased oil revenues by $179.7 million and was primarily the result of our ~~expenses~~development ~~for~~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 ~~periods~~widening ~~indicated:~~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.

	Six months ended June 30,					Increase / (Decrease)
	2014		2013			$			%
Expenses (in thousands):
Production:
Lease operating (a)	$	25,449	$	15,012		$	10,437		70	%
Production, severance, and ad valorem taxes	15,413		8,051			7,362			91	%
Total production expenses	40,862		23,063			17,799			77	%
Other:
Depletion, depreciation, and amortization	66,546		38,411			28,135			73	%
General and administrative (b)	20,858		6,840			14,018			205	%
Acquisition costs	1,825		151			1,674			1109	%
Derivative fair value loss (gain)	43,577		(5,706		)	49,283			-864	%
Accretion of discount on asset retirement obligations	417		311			106			34	%
Total operating	174,085		63,070			111,015			176	%
Interest	22,706		16,556			6,150			37	%
Income tax provision	749		418			331			79	%
Total expenses	$	197,540	$	80,044		$	117,496		147	%
Expenses (per BOE):
Production:
Lease operating (a)	$	7.23	$	7.84		$	(0.61	)	-8	%
Production, severance, and ad valorem taxes	4.38		4.21			0.17			4	%
Total production expenses	11.61		12.05			(0.44		)	-4	%
Other:
Depletion, depreciation, and amortization	18.90		20.07			(1.17		)	-6	%
General and administrative (b)	5.92		3.57			2.35			66	%
Acquisition costs	0.52		0.08			0.44			550	%
Derivative fair value loss (gain)	12.37		(2.98		)	15.35			-515	%
Accretion of discount on asset retirement obligations	0.12		0.16			(0.04		)	-25	%
Total operating	49.44		32.95			16.49			50	%
Interest	6.45		8.65			(2.20		)	-25	%
Income tax provision	0.21		0.22			(0.01		)	-5	%
Total expenses	$	56.10	$	41.82		$	14.28		34	%

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.

~~(a) For~~NGL revenues increased 101% to $41.2 million in the first ~~six~~nine months of 2014, ~~includes~~from ~~non-cash~~$20.5 ~~LOE~~million ~~for~~in ~~oil~~the ~~inventory~~first ~~assumed~~nine months of 2013 as a result of an increase in ~~acquisitions~~our NGL production volumes of ~~$1.6~~632 ~~million~~MBbls (and a $0.4790 per ~~BOE)~~Bbl ~~and~~increase ~~non-cash~~in ~~equity-based~~our ~~compensation~~average ofrealized $0NGL price.7 Our ~~million~~higher (NGL production increased NGL revenues by $0.19.5 ~~per~~million ~~BOE). For~~and ~~the~~was ~~first~~primarily ~~six~~the ~~months~~result of ~~2013~~our development program, ~~includes~~additional ~~non-cash~~production ~~equity-based~~from ~~compensation~~our of2014 ~~$15~~acquisitions,~~000~~ ~~($0~~and a reduction in flaring as described above.01 Our ~~per~~higher ~~BOE)~~average realized NGL price increased NGL revenues by $1.2 million.

(b) For the first six months of 2014, includes non-cash equity-based compensation of $7.6 million ($2.15 per BOE). For the first six months of 2013, includes corporate reorganization costs of $0.5 million ($0.27 per BOE), advisory fees of $0.5 million ($0.26 per BOE), and non-cash equity-based compensation of $98,000 ($0.05 per BOE).

Production expenses. LOE increased 70% to $25.4 million in the first six months of 2014 from $15.0 million in the first six months of 2013 as a result of an increase in production volumes as previously discussed, which contributed $12.6 million of additional LOE, partially offset by a $0.61 decrease in the average per BOE rate, which would have reduced LOE by $2.1 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 91% to $15.4 million in the first six months of 2014 from $8.1 million in the first six 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 6.4% in the first six months of 2014 as compared to 6.7% in the first six 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.

Table of Contents

~~DD&A~~Expenses. ~~DD&A~~ The ~~expense~~following ~~increased~~table ~~73%~~summarizes ~~to $66.5 million in the first six months of 2014 from $38.4 million in the first six months of 2013 primarily due to an increase in production volumes as previously discussed and an increase in~~ our ~~asset~~expenses ~~base~~for ~~subject to amortization as a result of our drilling activity and additional properties added in~~ the ~~Acquisitions.~~periods indicated:

G&A. G&A expense, excluding non-cash equity-based compensation, increased 97% to $13.3 million in the first six months of 2014 from $6.7 million in the first six months of 2013 primarily due to 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. Non-cash equity-based compensation allocated to G&A expense increased to $7.6 million in the first six months of 2014 from $98,000 in the first six months of 2013 primarily due to stock awards granted to employees as part of our incentive program.

	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)	35,164			13,294		21,870			165	%
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	209,096			137,043		72,053			53	%
Interest	35,208			26,595		8,613			32	%
Income tax provision	3,161			927		2,234			241	%
Total expenses	$	247,465		$	164,565	$	82,900		50	%

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)	5.72			4.28		1.44			34	%
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	34.00			44.13		(10.13		)	-23	%
Interest	5.73			8.56		(2.83		)	-33	%
Income tax provision	0.51			0.30		0.21			70	%
Total expenses	$	40.24		$	52.99	$	(12.75	)	-24	%

~~Derivative fair value loss~~ (~~gain~~a)~~. During~~ For the first ~~six~~nine months of 2014, weincludes ~~recorded~~non-cash anLOE ~~$43.6~~for ~~million~~oil ~~derivative~~inventory ~~fair~~assumed ~~value~~in ~~loss~~acquisitions asof ~~compared to a~~ $52.72 million ~~derivative~~($0.35 ~~fair~~per ~~value~~BOE) ~~gain~~and innon-cash ~~the~~equity-based ~~first~~compensation ~~six months~~ of ~~2013~~$1. ~~Since~~4 wemillion do($0.22 ~~not~~per ~~use~~BOE). For ~~hedge~~the ~~accounting,~~first ~~changes~~nine inmonths ~~fair value~~ of ~~our~~2013, ~~derivatives~~includes ~~are recognized as gains and losses in the current period. Included in these amounts were total~~ non-cash ~~settlements~~equity-based ~~paid~~compensation ~~on derivatives adjusted for recovered premiums~~ of $130.32 million ~~during the first six months of 2014 as compared to~~ ($0.807 ~~million~~per ~~during the first six months of 2013~~BOE).

~~Interest~~(b) For ~~expense. Interest expense increased 37% to $22.7 million in~~ the first ~~six~~nine months of 2014, ~~from~~includes ~~$16.6~~non-cash ~~million~~equity-based incompensation ~~the first six months~~ of ~~2013~~$14.4 ~~due~~million to($2.34 ~~higher~~per ~~long-term~~BOE) ~~debt balances~~ and ~~higher~~Encana ~~borrowing~~merger costs ~~in the first six months~~ of ~~2014~~$1.8 ~~when~~million ~~compared~~($0.29 toper BOE). For the first ~~six~~nine months of 2013~~. Our~~, ~~weighted~~includes non-~~average~~recurring ~~total~~Athlon ~~debt~~IPO ~~increased~~costs toof $~~745~~2.41 million ~~for~~($0.68 ~~the~~per ~~first~~BOE), ~~six~~corporate ~~months~~reorganization costs of ~~2014 as compared to~~ $~~457~~0.47 million ~~for~~($0.21 ~~the~~per ~~first~~BOE), ~~six~~non-cash ~~months~~equity-based compensation of ~~2013,~~$0.6 ~~primarily~~million ~~due~~($0.18 toper (iBOE) ~~funding~~, ~~requirements to develop our oil~~ and ~~natural~~advisory ~~gas~~fees ~~properties~~of ~~that~~$0.5 ~~are~~million ~~not covered by our operating cash flows and~~ (~~ii) funding~~$0.16 ofper ~~the Acquisitions~~BOE).

~~Our~~Production ~~weighted-average~~expenses. LOE ~~interest~~increased ~~rate,~~77% ~~net of capitalized interest, decreased~~ to 6$42.1% ~~for~~million in the first ~~six~~nine months of 2014 asfrom ~~compared to 7~~$23.2%8 ~~for~~million in the first ~~six~~nine months of 2013, ~~primarily~~as ~~due~~a toresult ~~the~~of ~~write~~an ~~off~~increase ofin ~~unamortized~~production ~~debt~~volumes ~~issuance~~as ~~costs~~previously indiscussed, ~~the~~which ~~second~~contributed ~~quarter~~$23.3 million of ~~2013~~additional LOE, partially offset by ~~the~~a ~~issuance~~$0.80 ofdecrease ~~our~~in ~~73/8%~~the ~~senior~~average ~~notes~~per inBOE ~~April 2013~~rate, awhich ~~portion~~would ofhave ~~the~~reduced ~~net~~LOE ~~proceeds~~by ~~from~~$4.9 ~~which~~million ~~were~~if ~~used~~production tohad ~~substantially~~been ~~pay~~unchanged. The ~~down~~decrease ~~outstanding~~in ~~borrowings~~our ~~under~~average ~~our~~LOE ~~credit~~per ~~agreement~~BOE ~~that~~rate ~~were~~was ~~subject~~attributable to ~~lower~~our ~~interest~~close ~~rates~~control ~~than~~of well servicing costs and leverage of our ~~senior~~centralized ~~notes~~service facilities and water handling systems.

~~The~~Production, ~~following~~severance, ~~table~~and ~~provides~~ad valorem taxes increased 100% to $27.1 million in the ~~components~~first nine months of ~~our~~2014 ~~interest~~from ~~expense~~$13.5 ~~for~~million in the ~~periods~~first ~~indicated:~~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.

	Six months ended June 30,						Increase /
	2014			2013			(Decrease)
	(in thousands)
Credit agreement	$	1,288		$	2,610		$	(1,322	)
73/8% senior notes	18,494			7,708			10,786
6% senior notes	6,515			—			6,515
Former second lien term loan	—			2,777			(2,777		)
Write off of debt issuance costs	—			2,838			(2,838		)
Amortization of debt issuance costs	1,358			734			624
Less: interest capitalized	(4,949		)	(111		)	(4,838		)
Total	$	22,706		$	16,556		$	6,150

Table of Contents

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 63% to $20.8 million in the first nine months of 2014 from $12.7 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 and (ii) $1.8 million of costs related to the pending merger with Encana, 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 $14.4 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.

Contract termination fee. We were a party to a Services Agreement which required it to compensate Apollo for consulting and advisory services. Upon the consummation of the Athlon IPO, we terminated the Services Agreement and, in connection with the termination, we 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 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

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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 June 30,

Six months ended June 30,

Three months ended September 30,

Nine months ended September 30,

2014

2013

2014

2013

(in thousands)

Development (a)

7470,~~733~~064

4142,~~215~~430

~~136~~206,~~111~~175

90132,~~453~~883

Exploration (b)

98123,~~015~~430

5765,~~479~~402

~~174~~297,~~427~~857

80145,~~032~~435

Total

~~172~~193,~~748~~494

98107,~~694~~832

~~310~~504,~~538~~032

~~170~~278,~~485~~318

(a) Includes asset retirement obligations incurred of $~~267,000~~0.3 million and $~~67,000~~0.2 million during the three months ended ~~June~~September 30, 2014 and 2013, respectively, and $~~449,000~~0.7 million and $~~226,000~~0.4 million during the ~~six~~nine months ended ~~June~~September 30, 2014 and 2013, respectively.

(b) Includes asset retirement obligations incurred of $~~270,000~~0.3 million and $~~100,000~~0.1 million during the three months ended ~~June~~September 30, 2014 and 2013, respectively, and $~~418,000~~0.7 million and $~~194,000~~0.3 million during the ~~six~~nine months ended ~~June~~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 ~~six~~nine months of 2014 were higher than in the first ~~six~~nine months of 2013 primarily due to our higher rig count, including the addition of horizontal drilling rigs.

In 2014, we expect our drilling capital expenditures to be approximately $700 million, plus an additional $25 million for leasing, infrastructure, capital workovers, and capitalized interest.

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 June 30,

Six months ended June 30,

Three months ended September 30,

Nine months ended September 30,

2014

2013

2014

2013

(in thousands)

Acquisitions of evaluated properties (a)

~~456~~184,~~484~~112

~~168~~3,113

~~497~~681,~~754~~866

25,~~770~~883

Acquisitions of unevaluated properties

~~426~~201,~~784~~966

717,~~495~~009

~~484~~686,~~458~~424

1330,~~977~~985

Total

~~883~~386,~~268~~078

720,~~663~~122

~~982~~1,~~212~~368,290

1636,~~747~~868

(a) Includes asset retirement obligations incurred of $1.90 million and $0.1 million during the three months ended ~~June~~September 30, 2014 and 2013, respectively, and $23.21 million and $~~265,000~~0.3 million during the ~~six~~nine months ended ~~June~~September 30, 2014 and 2013, respectively.

In the ~~second~~third quarter of 2014, we completed the ~~acquisitions~~acquisition of certain oil and natural gas properties and related assets in the Midland Basin from Summit for aapproximately ~~combined~~$202.5 million ~~purchase~~in ~~price~~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 $~~877~~394.10 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 ~~June~~September 30, 2014 and December 31, 2013, our working capital (defined as total current assets less total current liabilities) was a ~~surplus of~~ $8792.68 million deficit and a $44.4 million surplus, respectively. The ~~increase~~decrease in working capital was primarily due to ~~cash~~our ~~received~~2014 ~~from debt and equity offerings~~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 asprimarily ~~excess~~due ~~cash~~to ~~from~~amounts ~~equity~~accrued ~~and~~related ~~debt offerings are used~~ to ~~fund~~ 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 final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act on July 24, 2014. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act on July 24, 2014 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 ~~do not~~ have ~~any~~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:

	Six months ended June 30,						Increase /
	Nine months ended September 30,						Increase /
	2014			2013			(Decrease)
	(in thousands)
Net cash provided by operating activities	$	~~156~~274,~~325~~215		$	79137,~~231~~024		$	77137,~~094~~191
Net cash used in investing activities	(1,~~231~~817,~~619~~882		)	(~~178~~295,~~332~~003		)	(1,~~053~~522,~~287~~879		)
Net cash provided by financing activities	1,~~205~~435,~~164~~489			92345,~~777~~996			1,~~112~~089,~~387~~493
Net increase (decrease) in cash	$	~~129~~(108,~~870~~178	)	$	(6188,~~324~~017	)	$	~~136~~(296,~~194~~195	)

Cash flows from operating activities. Cash provided by operating activities increased $77137.12 million to $~~156~~274.32 million in the first ~~six~~nine months of 2014 from $79137.20 million in the first ~~six~~nine months of 2013, primarily due to an increase in our production margin ~~due~~as ~~to a 84% increase in~~ our total production volumes ~~and~~increased ~~a 10~~98% ~~increase in our per BOE average realized prices~~, partially offset by increased expenses as a result of having more producing wells in the first ~~six~~nine months of 2014 as compared to the first ~~six~~nine months of 2013.

Cash flows used in investing activities. Cash used in investing activities increased $1.15 billion to $1.2 8 billion in the first ~~six~~nine months of 2014 from $~~178~~295.3 0 million in the first ~~six~~nine months of 2013, primarily due to a $~~958~~1.3 ~~million~~billion increase in amounts paid to acquire oil and natural gas properties and a $94193.54 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 partner contributions. We periodically draw on our credit agreement to fund acquisitions and other capital commitments.

During the first ~~six~~nine months of 2014, we received net cash of $1.24 billion from financing activities, including $~~567~~562.72 million of net contributions from Athlon, ~~and~~ $639.1 million of net proceeds from the issuance of our 6% senior notes~~. During~~, ~~the~~and ~~first~~net ~~six~~borrowings ~~months~~ of ~~2013,~~$236 wemillion ~~received~~under ~~net~~our ~~cash~~credit ~~of $92~~agreement.~~8 million~~ Net ~~from~~borrowings ~~financing~~increased ~~activities,~~the ~~including~~outstanding ~~$487.1~~borrowings ~~million~~under ofour ~~net~~credit ~~proceeds~~agreement from ~~the~~none ~~issuance~~at ofDecember 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 $346.0 million from financing activities, including $296.0 million of net contributions from Athlon 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 $~~193.5~~237 million under our credit agreement, and a $75 million distribution to our 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.

InOur ~~2014, we expect our~~ drilling capital expenditures ~~to be approximately $700 million, plus an additional $25 million for leasing, infrastructure, capital workovers,~~ and ~~capitalized interest. The level of these and~~ other future expenditures isare 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 ~~six~~nine months of 2014, our average realized ~~oil,~~ natural gas, and NGL prices increased by 616%, ~~21%,~~ and 153%, respectively, as compared to the first ~~six~~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)
Q3 2014	9,950	$	92.52
Q4 2014	10,961	$	92.31
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 ~~June~~September 30, 2014, the borrowing base was $837.5 million and there were no$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 our proved reserves. In addition, obligations under our credit agreement are guaranteed by Athlon.

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

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

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

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

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

· a prohibition against incurring 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 ~~June~~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, we 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, 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, we completed a private placement of $650 million aggregate principal amount of 6% senior unsecured notes due 2022 (the “2022 Notes”). Athlon is 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 ~~June~~September 30, 2014, we were in compliance with all covenants in our senior notes.

Capitalization. At ~~June~~September 30, 2014, we had total assets of $23.81 billion and total capitalization of $2.59 billion, of which 5451% was represented by partner’s equity and 4649% by long-term debt. At December 31, 2013, we had total assets of $1.4 billion and total capitalization of $1.2 billion, of which 59% was represented by partners’ equity and 41% by long-term debt. The percentages of our capitalization represented by partners’ 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 June 30,				Six months ended June 30,
	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)	$	9386.9141	$	91104.8021	$	9390.7157	$	8894.1943
Oil ($/Bbl) (after impact of cash settled derivatives)	8683.9167		9194.0339		8785.5085		8790.5119
Natural gas ($/Mcf)	43.0758		3.7228		43.2697		3.5142
NGLs ($/Bbl)	3229.4360		2733.2776		3331.3877		2930.0887
Combined ($/BOE) (before impact of cash settled derivatives)	6863.4920		6474.0416		6866.7639		6267.6507
Combined ($/BOE) (after impact of cash settled derivatives)	6461.2351		6368.5918		6463.9850		6264.2552

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

Critical Accounting Policies and Estimates

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act on July 24, 2014 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.

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Counterparties

At ~~June~~September 30, 2014, we ~~did~~had ~~not~~committed ~~have~~10% aor ~~net~~greater ~~asset~~(in ~~position~~terms ~~with~~of ~~any~~fair market value) of our 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

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.

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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 ~~June~~September 30, 2014:

Period	Average Daily Swap Volume	Weighted- Average Swap Price		Net ~~Liability~~Asset Fair Market Value
	(Bbl)	(per Bbl)		(in thousands)
Q3 2014	9,950	$	92.52
Q4 2014	10,961	$	92.31	$	2,168
Q4 2014	10,961	92.31
Q1 2015	12,800	92.12
Q3-Q4 2014	10,455	92.41		$	(20,320	)
Q2 2015	12,800	92.12
Q1 2015	9,800	90.90
Q3 2015	11,800	93.69
Q2 2015	9,800	90.90
Q4 2015	11,800	93.69
Q3 2015	4,300	91.11
2015	12,296	92.88		22,727
Q4 2015	4,300	91.11
Q1 2016	2,500	92.35
2015	7,027	90.97		(16,224		)
Q2 2016	2,500	92.35
				$	(36,544	)
2016	1,243	92.35		2,718
				$	27,613

AsWe ofare ~~June 30,~~also ~~2014,~~a ~~the~~party ~~fair~~to ~~market~~Midland-Cushing ~~value~~basis ofdifferential ~~our~~swaps ~~oil~~for ~~derivative~~6,000 ~~contracts~~Bbls/D ~~was~~at ~~a net liability of~~ $~~36.~~5 ~~million~~. ~~Based~~19/Bbl onfor ~~our~~2015. At ~~open commodity derivative positions at June~~September 30, 2014, ~~a 10% increase in~~ the ~~NYMEX~~fair ~~WTI~~value ~~price~~of ~~would~~these ~~increase~~contracts ~~our~~was ~~net commodity derivative liability by approximately $43.8 million, while~~ a ~~10% decrease in the NYMEX WTI price would change our~~ net ~~commodity derivative~~ liability ~~to a net commodity derivative asset~~ of approximately $71.3 million.

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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.

Interest rate sensitivity

At ~~June~~September 30, 2014, we had outstanding debt of $1.154 billion, $500 million of which bears interest at a fixed rate of 73/8%, ~~and~~ $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 ~~June~~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 ~~June~~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 not be required to make our first assessment of internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Risk Factors” and elsewhere in our final prospectus filed with the SEC pursuant to Rule 424(b)(3) of the Securities Act on July 24, 2014, which could materially affect our business, financial condition, and/or future results. The risks described in our final prospectus are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

Item 6. Exhibits

Exhibit No.		Description
3.1		Certificate of Limited Partnership of Athlon Holdings LP (incorporated by reference to Exhibit 3.1 of Holdings’ Registration Statement on Form S-4, filed with the SEC on April 25, 2014).
3.2		Amended and Restated Agreement of Limited Partnership of Athlon Holdings LP, dated as of August 7, 2013 (incorporated by reference to Exhibit 10.11 to Athlon Energy Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, filed with the SEC on November 14, 2013).
3.3		Certificate of Incorporation of Athlon Finance Corp. (incorporated by reference to Exhibit 3.3 of Holdings’ Registration Statement on Form S-4, filed with the SEC on April 25, 2014).
3.4		By-laws of Athlon Finance Corp. (incorporated by reference to Exhibit 3.4 of Holdings’ Registration Statement on Form S-4, filed with the SEC on April 25, 2014).
4.1		Indenture between Wells Fargo Bank, N.A., as trustee, Athlon Holdings LP and Athlon Finance Corp., as issuers, and Athlon Energy Inc., as guarantor, dated May 1, 2014 relating to the 6.000% Senior Notes due 2022 (including form of Note) (incorporated by reference to Exhibit 4.1 of Athlon Energy Inc.’s Current Report on Form 8-K, filed with the SEC on May 2, 2014).
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 Holdings’ Current Report on Form 8-K, filed with the SEC on September 4, 2014).
10.1		Employment Agreement, dated as of August 7, 2013, by and between Athlon Holdings LP and Bud W. Holmes (incorporated by reference to Exhibit 10.7 of Athlon Energy Inc.’s Registration Statement on Form S-1 (File No. 333-196823), filed with the SEC on June 17, 2014).
10.2+		Form of Restricted Stock Grant Notice—Executive (incorporated by reference to Exhibit (e)(12) to Athlon Energy Inc.’s Schedule 14D-9, filed with the SEC on October 10, 2014).
10.2		Form of Restricted Stock Grant Notice—Executive (incorporated by reference to Exhibit 10.17 of Athlon Energy Inc.’s Registration Statement on Form S-1 (File No. 333-196823), filed with the SEC on June 17, 2014).
10.3+		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 Holdings’ Current Report on Form 8-K, filed with the SEC on October 2, 2014).
10.3		Purchase and Sale Agreement, dated as of April 8, 2014 by and among Hibernia Holdings, LLC and Hibernia Resources, LLC, as Sellers, and Athlon Energy Inc., as Purchaser (incorporated by reference to Exhibit 2.1 of Athlon Energy Inc.’s Current Report on Form 8-K, filed with the SEC on June 5, 2014).
10.4+		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 Holdings’ Current Report on Form 8-K, filed with the SEC on October 2, 2014).
10.4		Purchase and Sale Agreement, dated as of April 8, 2014 by and among Piedra Energy II, LLC, Piedra Operating, LLC, and the other sellers party thereto, as Sellers, and Athlon Energy Inc., as Purchaser (incorporated by reference to Exhibit 2.2 of Athlon Energy Inc.’s Current Report on Form 8-K, filed with the SEC on June 5, 2014).
10.5		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*		Athlon Holdings LP Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).
31.2*		Athlon Holdings LP Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).
31.3*		Athlon Finance Corp. Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).
31.4*		Athlon Finance Corp. Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).
32.1*		Athlon Holdings LP Section 1350 Certification (Principal Executive Officer).
32.2*		Athlon Holdings LP Section 1350 Certification (Principal Financial Officer).
32.3*		Athlon Finance Corp. Section 1350 Certification (Principal Executive Officer).
32.4*		Athlon Finance Corp. 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.

34+ 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 HOLDINGS LP
	ATHLON FINANCE CORP.
	/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: August 21, 2014
Date: November 12, 2014

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