News Column

ATHLON HOLDINGS LP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 21, 2014

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes in "Item 1. Financial Statements". The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. Actual results could differ materially from those discussed in these forward-looking statements. We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under law. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under "Cautionary Note Regarding Forward-Looking Information" and "Risk Factors" in our final prospectus 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. 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 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. All other New Holdings Units are held by Athlon.



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 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. 18 --------------------------------------------------------------------------------



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We completed the acquisitions of certain oil and natural gas properties and related assets in the Midland Basin (the "Acquisitions") for a combined purchase price of approximately $877.1 million, subject to post-closing adjustments. We also evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with the technical capabilities of our management team can generate attractive rates of return as we develop our extensive resource base. Additionally, by focusing on concentrated acreage positions, we can build and own centralized production infrastructure, including saltwater disposal facilities, which enable us to reduce reliance on outside service companies, minimize costs, and increase our returns. Results of Operations



Comparison of Quarter Ended June 30, 2014 to Quarter Ended June 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) 2014 2013 $ % Revenues (in thousands): Oil $ 114,137$ 54,609$ 59,528 109 % Natural gas 8,687 4,363 4,324 99 % NGLs 13,686 6,193 7,493 121 % Total revenues $ 136,510$ 65,165$ 71,345 109 % Average realized prices: Oil ($/Bbl) (before impact of cash settled derivatives) $ 93.91 $ 91.80 $ 2.11 2 % Oil ($/Bbl) (after impact of cash settled derivatives) $ 86.91 $ 91.03 $ (4.12 ) -5 % Natural gas ($/Mcf) $ 4.07 $ 3.72 $ 0.35 9 % NGLs ($/Bbl) $ 32.43 $ 27.27 $ 5.16 19 % Combined ($/BOE) (before impact of cash settled derivatives) $ 68.49 $ 64.04 $ 4.45 7 % Combined ($/BOE) (after impact of cash settled derivatives) $ 64.23 $ 63.59 $ 0.64 1 % Total production volumes: Oil (MBbls) 1,215 595 620 104 % Natural gas (MMcf) 2,134 1,174 960 82 % NGLs (MBbls) 422 227 195 86 % Combined (MBOE) 1,993 1,018 975 96 % Average daily production volumes: Oil (Bbls/D) 13,356 6,537 6,819 104 % Natural gas (Mcf/D) 23,453 12,897 10,556 82 % NGLs (Bbls/D) 4,637 2,496 2,141 86 % Combined (BOE/D) 21,901 11,183 10,718 96 %



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.

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Table of Contents 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. 20

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

-------------------------------------------------------------------------------- (a) For the second quarter of 2014, includes non-cash LOE for oil inventory assumed in acquisitions of $1.6 million ($0.82 per BOE) and non-cash equity-based compensation of $0.4 million ($0.21 per BOE). For the second quarter of 2013, includes non-cash equity-based compensation of $8,000 ($0.01 per BOE). (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 21

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an increase in our asset base subject to amortization as a result of our drilling activity and additional properties added in the Acquisitions.

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. Derivative fair value loss (gain). During the second quarter of 2014, we recorded a $32.4 million derivative fair value loss as compared to a $12.6 million derivative fair value gain in the second quarter of 2013. Since we do not use hedge accounting, changes in fair value of our derivatives are recognized as gains and losses in the current period. Included in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums of $8.5 million during the second quarter of 2014 as compared to $0.5 million during the second quarter of 2013. Interest expense. Interest expense increased 12% to $13.5 million in the second quarter of 2014 from $12.1 million in the second quarter of 2013 due to higher long-term debt balances and higher borrowing costs in the second quarter of 2014 when compared to the second quarter of 2013. Our weighted-average total debt increased to $970.1 million for the second quarter of 2014 as compared to $517.0 million for the second 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 the Acquisitions. Our weighted-average interest rate, net of capitalized interest, decreased to 6.2% for the second quarter of 2014 as compared to 9.3% for the second quarter of 2013, primarily due to the write off of unamortized debt issuance costs in the second quarter of 2013, partially offset by the issuance of our 73/8% senior notes in April 2013, a portion of the net proceeds from which were used to reduce outstanding borrowings under our credit agreement that were subject to lower interest rates than our senior notes. The following table provides the components of our interest expense for the periods indicated: 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 22

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Comparison of Six Months Ended June 30, 2014 to Six Months Ended June 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: 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 %



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.

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 % Our average oil differential to NYMEX WTI widened to $7.10 per Bbl for the first six months of 2014 as compared to $6.09 per Bbl for the first six 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 $0.53 per Mcf for the first six months of 2014 as compared to $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. 23 --------------------------------------------------------------------------------



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Oil revenues increased 101% to $201.2 million in the first six months of 2014 from $100.3 million in the first six months of 2013 as a result of an increase in our oil production volumes of 1,010 MBbls 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 a higher average NYMEX price, 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 $16.1 million in the first six months of 2014 from $7.7 million in the first 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 by $5.5 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 $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. 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. 24

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

-------------------------------------------------------------------------------- (a) For the first six months of 2014, includes non-cash LOE for oil inventory assumed in acquisitions of $1.6 million ($0.47 per BOE) and non-cash equity-based compensation of $0.7 million ($0.19 per BOE). For the first six months of 2013, includes non-cash equity-based compensation of $15,000 ($0.01 per BOE).



(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. 25

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DD&A. DD&A expense increased 73% 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 base subject to amortization as a result of our drilling activity and additional properties added in the Acquisitions. 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. Derivative fair value loss (gain). During the first six months of 2014, we recorded an $43.6 million derivative fair value loss as compared to a $5.7 million derivative fair value gain in the first six 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 of $13.3 million during the first six months of 2014 as compared to $0.8 million during the first six months of 2013. Interest expense. Interest expense increased 37% to $22.7 million in the first six months of 2014 from $16.6 million in the first six months of 2013 due to higher long-term debt balances and higher borrowing costs in the first six months of 2014 when compared to the first six months of 2013. Our weighted-average total debt increased to $745.4 million for the first six months of 2014 as compared to $457.4 million for the first six 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 the Acquisitions. Our weighted-average interest rate, net of capitalized interest, decreased to 6.1% for the first six months of 2014 as compared to 7.2% for the first six months of 2013, primarily due to the write off of unamortized debt issuance costs in the second quarter of 2013, partially offset by the issuance of our 73/8% senior notes in April 2013, a portion of the net proceeds from which were used to substantially pay down outstanding borrowings under our credit agreement that were subject to lower interest rates than our senior notes. The following table provides the components of our interest expense for the periods indicated: 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 26

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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, 2014 2013 2014 2013 (in thousands) Development (a) $ 74,733$ 41,215$ 136,111$ 90,453 Exploration (b) 98,015 57,479 174,427 80,032 Total $ 172,748$ 98,694$ 310,538$ 170,485

-------------------------------------------------------------------------------- (a) Includes asset retirement obligations incurred of $267,000 and $67,000 during the three months ended June 30, 2014 and 2013, respectively, and $449,000 and $226,000 during the six months ended June 30, 2014 and 2013, respectively. (b) Includes asset retirement obligations incurred of $270,000 and $100,000 during the three months ended June 30, 2014 and 2013, respectively, and $418,000 and $194,000 during the six months ended June 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 months of 2014 were higher than in the first six 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, 2014 2013 2014 2013 (in thousands) Acquisitions of evaluated properties (a) $ 456,484$ 168$ 497,754$ 2,770 Acquisitions of unevaluated properties 426,784 7,495 484,458 13,977 Total $ 883,268$ 7,663$ 982,212$ 16,747

-------------------------------------------------------------------------------- (a) Includes asset retirement obligations incurred of $1.9 million during the three months ended June 30, 2014 and $2.2 million and $265,000 during the six months ended June 30, 2014 and 2013, respectively. In the second quarter of 2014, we completed the acquisitions of certain oil and natural gas properties and related assets in the Midland Basin for a combined purchase price of approximately $877.1 million, subject to post-closing adjustments. Funding of working capital. As of June 30, 2014 and December 31, 2013, our working capital (defined as total current assets less total current liabilities) was a surplus of $87.6 million and $44.4 million, respectively. The increase in working capital was due to cash received from debt and equity offerings. 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 27 --------------------------------------------------------------------------------



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the remainder of 2014, we expect to have a working capital deficit as excess cash from equity and 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 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 / 2014 2013 (Decrease) (in thousands)



Net cash provided by operating activities $ 156,325$ 79,231$ 77,094 Net cash used in investing activities

(1,231,619 ) (178,332 ) (1,053,287 ) Net cash provided by financing activities 1,205,164 92,777 1,112,387 Net increase (decrease) in cash $ 129,870$ (6,324 )$ 136,194 Cash flows from operating activities. Cash provided by operating activities increased $77.1 million to $156.3 million in the first six months of 2014 from $79.2 million in the first six months of 2013, primarily due to an increase in our production margin due to a 84% increase in our total production volumes and a 10% 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 months of 2014 as compared to the first six months of 2013. Cash flows used in investing activities. Cash used in investing activities increased $1.1 billion to $1.2 billion in the first six months of 2014 from $178.3 million in the first six months of 2013, primarily due to a $958.3 million increase in amounts paid to acquire oil and natural gas properties and a $94.5 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 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 months of 2014, we received net cash of $1.2 billion from financing activities, including $567.7 million of net contributions from Athlon and $639.1 million of net proceeds from the issuance of our 6% senior notes. During the first six months of 2013, we received net cash of $92.8 million from financing activities, including $487.1 million of net proceeds from the issuance of 28

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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 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. 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. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing 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 months of 2014, our average realized oil, natural gas, and NGL prices increased by 6%, 21%, and 15% respectively, as compared to the first six months of 2013. 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: Average Daily Weighted- Swap Average Period Volume 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 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. 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 29

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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. 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 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: Applicable Applicable Unused Margin for Margin for Base Ratio of Outstanding Borrowings to Borrowing Base Commitment Fee Eurodollar Loans 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

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 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 30, 2014, we were in compliance with all covenants in our senior notes. Capitalization. At June 30, 2014, we had total assets of $2.8 billion and total capitalization of $2.5 billion, of which 54% was represented by partner's equity and 46% 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: 31 --------------------------------------------------------------------------------

Table of Contents Three months ended June 30, Six months ended June 30, 2014 2013 2014 2013 Average realized prices: Oil ($/Bbl) (before impact of cash settled derivatives) $ 93.91 $ 91.80 $ 93.71$ 88.19 Oil ($/Bbl) (after impact of cash settled derivatives) 86.91 91.03 87.50 87.51 Natural gas ($/Mcf) 4.07 3.72 4.26 3.51 NGLs ($/Bbl) 32.43 27.27 33.38 29.08 Combined ($/BOE) (before impact of cash settled derivatives) 68.49 64.04 68.76 62.65 Combined ($/BOE) (after impact of cash settled derivatives) 64.23 63.59 64.98 62.25 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.


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