News Column

PARSLEY ENERGY, INC. - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operation

August 14, 2014

The following discussion and analysis should be read in conjunction with the accompanying financial statements and related notes. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed above, in "Cautionary Note Regarding Forward-Looking Statements," and in our final prospectus dated May 22, 2014 and filed with the Securities and Exchange Commission ("SEC") pursuant to Rule 424(b) under the Securities Act, on May 27, 2014 under the heading "Risk Factors," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.



Our Predecessor and Parsley Energy, Inc.

Parsley Energy Inc. (together with its subsidiaries, the "Company") was formed in December 2013 and does not have historical financial operating results. For purposes of this discussion, our accounting predecessors are Parsley Energy, LLC ("Parsley LLC") and its predecessors. Parsley LLC was formed in June 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. Concurrent with the formation of Parsley LLC all of the interest holders in Parsley Energy, L.P. ("Parsley LP"), Parsley Energy Management, LLC ("PEM"), and Parsley Energy Operations, LLC ("PEO") exchanged their interests in each such entity for interests in Parsley LLC (the "Exchange"). The Exchange was treated as a reorganization of entities under common control. We are a holding company whose sole material asset consists of 32,145,296 units in Parsley LLC. We are the managing member of Parsley LLC and are responsible for all operational, management and administrative decisions of Parsley LLC, and we consolidate the financial results of Parsley LLC and its subsidiaries. Overview We are an independent oil and natural gas company focused on the acquisition, development, and exploitation of unconventional oil and natural gas reserves in the Permian Basin. Our properties are located in the Midland and Delaware Basins and our activities have historically been focused on the vertical development of the Spraberry, Wolfberry and Wolftoka Trends of the Midland Basin. Our vertical wells in the area are drilled into stacked pay zones that include the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline), Strawn, Atoka and Mississippian formations. We have begun to supplement our vertical development drilling activity with horizontal wells and expect to target various stacked pay intervals in the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline), and Atoka shales. Our Properties At June 30, 2014, our acreage position was 114,249 net acres. The vast majority of our acreage is located in the Midland Basin, and the majority of our identified vertical and horizontal drilling locations are located in our Midland Basin-Core area. Our Midland Basin-Core area contains areas of Andrews, Glasscock, Howard, Martin, Midland, Reagan, and Upton Counties. From the time we began drilling operations in November 2009 through June 30, 2014, we have drilled and placed on production approximately 417 vertical wells across our acreage in the Midland Basin. We are currently operating eight vertical rigs in the Midland Basin. In addition to our vertical drilling program in the Midland Basin, we initiated our horizontal development program with one rig during the fourth quarter of 2013 and have increased to three operated horizontal rigs. Through June 30, 2014, we have drilled and placed on production 5 horizontal wells in the Midland Basin. Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014 and expect to drill three vertical appraisal wells in 2014. As of June 30, 2014, we have identified 1,677 potential horizontal drilling locations, 1,555 80- and 40-acre potential vertical drilling locations and 1,992 20-acre potential vertical drilling locations on our existing acreage, which does not include any locations in Gaines County (Midland Basin) or in our Southern Delaware Basin acreage. As we continue to expand our drilling activity to our undeveloped acreage, we expect to identify additional horizontal and vertical locations. As of June 30, 2014, we had interests in 571 gross (311.5 net) producing wells across our properties. We currently operate 99% of the wells in which we have an interest. 28

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How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

- production volumes;



- realized prices on the sale of oil, natural gas and NGLs, including the

effect of our commodity derivative contracts;

- lease operating expenses; - capital expenditures; and - Adjusted EBITDA. Sources of Our Revenues Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended June 30, 2014 and 2013, our revenues were derived 75% and 81%, respectively, from oil sales and 25% and 19%, respectively, from natural gas and NGLs sales. For the six months ended June 30, 2014 and 2013, our revenues were derived 77% and 82%, respectively, from oil sales and 23% and 18%, respectively, from natural gas and NGLs sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. NGLs production and sales are included in our natural gas production and sales. Production Volumes



The following table presents historical production volumes for our properties for the three and six months ended June 30, 2014 and 2013.

For the Three Months Ended For the Six Months Ended June 30, June 30, 2014 2013 2014 2013 Oil (MBbls) 654 236 1,145 403 Natural gas and natural gas liquid (MMcf) 3,717 1,197 5,717 1,816 Total (MBoe) 1,274 436 2,099 706 Average net production (Boe/d) 13,995 4,786 11,596 3,899



Production volumes directly impact our results of operations.

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic drill-bit growth as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions.



Realized Prices on the Sale of Oil, Natural Gas and NGLs

The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing, Oklahoma transport hub and the Gulf Coast refineries. Periodically, logistical and infrastructure constraints at the Cushing, Oklahoma transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lower prices for Midland WTI. These lower prices have adversely affected the prices we realize on oil sales and increased our differential to NYMEX WTI 29 -------------------------------------------------------------------------------- The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas' proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. The following table provides the high and low prices for NYMEX WTI and NYMEXHenry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil and natural gas normally sells at a discount to the NYMEX WTI and the NYMEX Henry Hub price, respectively. Because our NGLs are reported in our natural gas revenue, our differential to NYMEX Henry Hub is positive. Three Months Ended June 30, Six Months Ended June 30, 2014 2013 2014 2013 Oil NYMEX WTI High $ 107.26 98.44 $ 107.26$ 98.44 NYMEX WTI Low $ 99.42 86.68 $ 91.66$ 86.68 Differential to Average NYMEX WTI $ (8.94 ) (1.79 ) $ (5.52 )$ (5.83 ) Natural Gas NYMEX Henry Hub High $ 4.83 $ 4.41$ 6.15$ 4.41 NYMEX Henry Hub Low $ 4.28 $ 3.57$ 4.00$ 3.11 Differential to Average NYMEX Henry Hub $ 0.98 $ 0.31



$ 0.60$ 0.58

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the three months ended June 30, 2014, the NYMEX-WTI oil price ranged from a high of $107.26 per Bbl to a low of $99.42 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.83 per MMBtu to a low of $4.28 per MMBtu. For the six months ended June 30, 2014, the NYMEX WTI oil price ranged from a high of $107.26 per Bbl to a low of $91.66 per Bbl, while the NYMEX Henry Hub natural gas price ranged from a high of $6.15 per MMBtu to a low of $4.00 per MMBtu. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil production. By removing a significant portion of price volatility associated with our oil production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our derivatives contract prices are higher than market prices. We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis including hedging our natural gas production. We are not under an obligation to hedge a specific portion of our oil or gas production. 30 --------------------------------------------------------------------------------



Our positions hedging production as of June 30, 2014 were as follows:

VOLUME SHORT PUT LONG PUT SHORT CALL Description and Production Period (Bbls) PRICE ($/Bbl) PRICE ($/Bbl) PRICE ($/Bbl) Crude Oil Put Spreads: July 2014-August 2014 59,000 $ 55.00 $ 90.00 July 2014-October 2014 170,000 $ 65.00 $ 90.00 August 2014 9,000 $ 50.00 $ 83.00 September 2014 9,000 $ 60.00 $ 80.00 October 2014 9,000 $ 50.00 $ 90.00 February 2015-June 2015 500,000 $ 60.00 $ 85.00 January 2015-February 2016 1,080,000 $ 60.00 $ 90.00 March 2016-June 2016 700,000 $ 65.00 $ 85.00 July 2014-June 2016 300,000 $ 70.00 $ 85.00 July 2016-December 2016 1,800,000 $ 70.00 $ 85.00 Crude Oil Three Way Collars: August 2014-October 2014 135,000 $ 65.00 $ 90.00 $ 125.00 November 2014-January 2015 300,000 $ 55.00 $ 87.50 $ 120.00 July 2014-February 2016 610,000 $ 65.00 $ 85.00 $ 110.00 March 2015-June 2016 600,000 $ 65.00 $ 85.00 $ 120.00 VOLUME SHORT PUT LONG PUT SHORT CALL Description and Production Period (MMBtu) PRICE ($/MMBtu) PRICE ($/MMBtu) PRICE ($/MMBtu) Natural Gas Three Way Collars: August 2014-December 2014 1,000,000 $ 4.00 $ 5.00 $ 5.57 January 2015-December 2015 3,600,000 $ 3.75 $ 4.50 $ 5.25



Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons: Incentive Unit Compensation For the six months ended June 30, 2014 and the year ended December 31, 2013, within Incentive unit compensation, are amounts attributable to incentive units that, pursuant to the terms of the Parsley LLC limited liability company agreement at that date, were only entitled to a payout after a specified level of cumulative cash distributions had been received by Natural Gas Partners, through NGP X US Holdings, L.P., (collectively, "NGP") and other investors, including all of our executive officers (the "PSP Members"). At December 31, 2013 and June 30, 2014, the incentive units were being accounted for as liability-classified awards pursuant to ASC Topic 718, "Compensation-Stock Compensation", as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. As part of the transactions described below "Corporate Reorganization", the Parsley LLC limited liability company agreement was amended. Such amendments, among other things, converted all outstanding incentive units in Parsley LLC into PE Units. A portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock, instead of in cash. As a result, on May 29, 2014, we accounted for the incentive unit awards as equity-classified awards pursuant to ASC Topic 718. This resulted in the recognition of $50.1 million of stock based compensation equal to the excess of the modified awards' fair value (based on the initial offering price of $18.50) over the amount of cumulative compensation cost recognized prior to that date. 31 --------------------------------------------------------------------------------

Stock Based Compensation Restricted stock awards are awards of Class A Common Stock that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. Restricted stock unit awards are awards of restricted stock units that are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restriction. Each restricted stock unit represents the right to receive one share of Class A Common Stock. The fair value of such awards was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods. On May 29 2014, 738,474 shares of restricted stock and 23,649 restricted stock units were granted to our directors, management, and employees. Stock based compensation expense related to restricted stock and restricted stock units was $0.3 million for the three and six months ended June 30, 2014. There was approximately $13.8 million of unamortized compensation expense relating to outstanding restricted stock and restricted stock units at June 30, 2014. Public Company Expenses We expect to incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, increased scope of our operations as a result of recent activities and costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations. Corporate Reorganization The historical condensed consolidated and combined financial statements are based on the financial statements of our accounting predecessors, Parsley LLC and its predecessors, prior to the reorganization that occurred in connection with the Offering as described in Note 1. Organization and Nature of Operations - Corporate Reorganization. As a result, the historical condensed consolidated and combined financial data may not give you an accurate indication of what our actual results would have been if the transactions described in Note 1. Organization and Nature of Operations - Corporate Reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In addition, we have entered into the TRA with certain members of Parsley LLC (as set forth in the TRA) (the "TRA Holders") in connection with the Offering. This agreement generally provides for the payment by us to a TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in periods after this offering as a result of (i) any tax basis increases resulting from the contribution in connection with the Offering by such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash at our or Parsley LLC's election) and (iii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. We will retain the benefit of the remaining 15% of these cash savings. Income Taxes Our accounting predecessors are limited liability companies or limited partnerships and therefore not subject to U.S. federal income taxes. Accordingly, no provision for U.S. federal income tax has been provided for in our historical results of operations. We are taxed as a corporation under the Internal Revenue Code and subject to U.S. federal income tax at a statutory rate of 35.7% of pretax earnings, and, as such, the amount of our future U.S. federal income tax will be dependent upon our future taxable income.



The Company's operations located in Texas are subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 1.0% of income that is apportioned to Texas.

Increased Drilling Activity We began drilling operations in November 2009. We currently operate eight vertical drilling rigs and three horizontal drilling rigs on our properties. In the six months ended June 30, 2014, we have spent $194.3 million for drilling and completing wells. This compares to $268.4 million that we spent in all of 2013 for drilling and completion. 32 -------------------------------------------------------------------------------- The amount and timing of our future capital expenditures is largely discretionary and within our control. We could choose to defer a portion of planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Results of Operations



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Oil and Natural Gas Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period's respective average prices and production volumes: Three Months Ended June 30, 2014 2013 $ Change % Change Revenues (in thousands, except percentages): Oil sales $ 61,735$ 21,421$ 40,314 188 % Natural gas and natural gas liquid sales 20,569 5,153 15,416 299 % Total revenues $ 82,304$ 26,574$ 55,730 210 % Average sales prices(1): Oil sales, without realized derivatives (per Bbls) $ 94.40$ 90.77$ 3.63 4 % Oil sales, with realized derivatives (per Bbls) $ 91.74$ 76.03$ 15.71 21 % Natural gas and NGLs, without realized derivatives (per Mcf) $ 5.53$ 4.30$ 1.23 29 % Natural gas and NGLs, with realized derivatives (per Mcf) $ 5.58$ 4.30$ 1.27 30 % Average price per BOE, without realized derivatives $ 64.63$ 61.02$ 3.61 6 % Average price per BOE, with realized derivatives $ 63.40$ 53.03$ 10.37 20 % Production: Oil (MBbls) 654 236 418 177 % Natural gas and natural gas liquid (MMcf) 3,717 1,197 2,520 211 % Total (MBoe)(2) 1,274 436 838 192 % Average daily production volume: Oil (Bbls/d) 7,187 2,593 4,594 177 % Natural gas and natural gas liquids (Mcf/d) 40,846 13,154 27,692 211 % Total (Boe/d) 13,995 4,786 9,209 192 %



(1) Average prices shown in the table reflect prices both before and after the

effects of our realized commodity hedging transactions. Our calculation of

such effects includes both realized gains and losses on cash settlements for

commodity derivative transactions and premiums paid or received on options

that settled during the period.

(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based

on an approximate energy equivalency. This is an energy content correlation

and does not reflect a value or price relationship between the commodities.

33 --------------------------------------------------------------------------------



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

Three Months Ended June 30, 2014 2013 Average realized oil price ($/Bbl) $ 94.40$ 90.77 Average NYMEX ($/Bbl) $ 103.34$ 92.56 Differential to NYMEX $ (8.94 )$ (1.79 ) Average realized oil price to NYMEX percentage 91 %



98 %

Average realized natural gas price ($/Mcf) $ 5.53 $

4.30 Average NYMEX ($/Mcf) $ 4.56 $ 3.99 Differential to NYMEX $ 0.98 $ 0.31 Average realized natural gas to NYMEX percentage 121 %



108 %

Oil revenues increased 188% from $21.4 million during the three months ended June 30, 2013 to $61.7 million during the three months ended June 30, 2014. The increase is attributable to higher oil production volumes of 654 MBbls in conjunction with an increase in average oil prices to $94.40 per barrel for the three months ended June 30, 2014. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $37.9 million while increases in oil prices accounted for a positive change of $2.4 million. Our production volumes significantly increased due to increased drilling activities and acquisitions during the period. Natural gas and NGLs revenues increased by 299% from $5.2 million during the three months ended June 30, 2013 to $20.6 million during the three months ended June 30, 2014. The revenue increase is a result of an increase in volumes sold of 3,717 MMcf, which was partially offset by a decrease of 6.1% in our average realized natural gas and NGLs prices, for the three months ended June 30, 2014. Natural gas revenue includes revenue from the sale of NGLs volumes. Of the overall changes in natural gas and NGLs sales, increases in natural gas and NGLs production volumes accounted for a positive change of $10.8 million while increases in natural gas and NGLs prices accounted for a positive change of $4.6 million. Operating Expenses. The following table summarizes our expenses for the periods indicated: Three Months Ended June 30, 2014 2013 $ Change % Change Operating expenses (in thousands, except percentages): Lease operating expenses $ 9,668$ 4,489$ 5,179 115 % Production and ad valorem taxes 5,511 1,372 4,139 302 % Depreciation, depletion and amortization 20,446 4,943 15,503 314 % General and administrative expenses 6,943 1,923 5,020 261 % Incentive unit compensation 50,559 - 50,559 100 % Stock based compensation 294 - 294 100 % Accretion of asset retirement obligations 117 36 81 225 % Total operating expenses $ 93,538$ 12,763$ 80,775 633 % Expense per Boe: Lease operating expenses $ 7.59$ 10.31$ (2.72 ) (26 )% Production and ad valorem taxes 4.33 3.15 1.18 37 % Depreciation, depletion and amortization 16.05 11.35 4.70 41 % General and administrative expenses 5.45 4.42 1.03 23 % Incentive unit compensation 39.70 - 39.70 100 % Stock based compensation 0.23 - 0.23 100 % Accretion of asset retirement obligations 0.09 0.08 0.01 - %



Total operating expenses per Boe $ 73.44$ 29.31$ 44.13

151 % 34 -------------------------------------------------------------------------------- Lease Operating Expenses. Lease operating expenses increased 115% from $4.5 million during the three months ended June 30, 2013 to $9.7 million during the three months ended June 30, 2014. The increase is primarily due to the higher operated well count in the three month period ended June 30, 2014 as compared to the prior year period. On a per Boe basis, lease operating expenses decreased from $10.31 per Boe to $7.59 per Boe during this period. This decrease was attributable to a decrease in costs for well servicing and decreased workover and water disposal activity. Production and Ad Valorem Taxes. Production and ad valorem taxes increased $4.1 million from $1.4 million during the three months ended June 30, 2013 to $5.5 million during the three months ended June 30, 2014 due to increased wellhead revenue resulting from higher production. Our increased drilling activity led to a higher number of wells brought on production during the three months ended June 30, 2014 compared to the three months ended June 30, 2013. Depreciation, Depletion and Amortization. DD&A expense increased by $15.5 million from $4.9 million during the three months ended June 30, 2013 to $20.4 million for the three months ended June 30, 2014 due to an increase in capitalized costs and production volumes. DD&A expense per BOE increased by $4.70 primarily due to the increase in developmental costs and leasehold acquisitions. General and Administrative Expenses. General and administrative expenses increased $5.0 million from $1.9 million during the three months ended June 30, 2013 to $6.9 million during the three months ended June 30, 2014 primarily due to higher payroll and payroll-related costs as we hired additional employees to manage our growing asset base, higher rig count and increased production. Incentive unit compensation. Incentive unit compensation increased $50.6 million during the three months ended June 30, 2014 primarily due to the acceleration of the expense due to the Offering and Corporate Reorganization. Stock based compensation. Stock based compensation increased $0.3 million for the three months ended June 30, 2014 due to the issuance and amortization of the restricted stock and restricted stock units issued on May 29, 2014. No stock based compensation expenses were incurred during the three month period ended June 30, 2013.



Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

Three Months Ended June 30, 2014 2013 $ Change % Change Other income (expense) (in thousands, except percentages): Interest expense, net $ (9,906 )$ (2,936 )$ (6,970 ) 237 % Income (loss) from equity investment (178 ) 88 (266 ) (302 )% Derivative income (loss) (14,353 ) 484 (14,837 ) (3065 )% Other income (expense) (24 ) 45 (69 ) (153 )% Total other expense, net $ (24,461 )$ (2,319 )$ (22,142 ) 955 %



Interest Expense. Interest expense increased $7.0 million from $2.9 million during the three months ended June 30, 2013 to $9.9 million in the three months ended June 30, 2014 primarily due to higher weighted-average outstanding borrowings under our credit facilities and accrued interest related to the Notes.

Derivative Loss. Loss on derivative instruments increased $14.8 million from a gain of $0.5 million during the three months ended June 30, 2013 to a loss of $14.4 million during the three months ended June 30, 2014 primarily as a result of the impact of unfavorable commodity price changes on increased hedging activities. Income Tax Expense Our operations are taxed at a combined U.S. federal and state effective tax rate of 35.7%. As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax. During the three months ended June 30, 2014, we recognized $1.8 million of expense, an increase of $1.4 million, or 417%, as compared to the $0.3 million we recognized during the three months ended June 30, 2013. This increase was attributable to our status as a corporation subject to U.S. federal income tax as well as a net increase in operating income, the components of which are discussed above. 35 --------------------------------------------------------------------------------

Results of Operations



Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Oil and Natural Gas Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period's respective average prices and production volumes: Six Months Ended June 30, 2014 2013 $ Change % Change Revenues (in thousands, except percentages): Oil sales $ 107,563$ 34,953$ 72,610 208 % Natural gas and natural gas liquid sales 32,471 7,878 24,593 312 % Total revenues $ 140,034$ 42,831$ 97,203 227 % Average sales prices(1): Oil sales, without realized derivatives (per Bbls) $ 93.94$ 86.73$ 7.21 8 % Oil sales, with realized derivatives (per Bbls) $ 91.63$ 76.37$ 15.26 20 % Natural gas and NGLs, without realized derivatives (per Mcf) $ 5.68$ 4.34$ 1.34 31 % Natural gas and NGLs, with realized derivatives (per Mcf) $ 5.64$ 4.34$ 1.31 30 % Average price per BOE, without realized derivatives $ 66.72$ 60.70$ 6.02 10 % Average price per BOE, with realized derivatives $ 65.36$ 54.78$ 10.59 19 % Production: Oil (MBbls) 1,145 403 742 184 % Natural gas and natural gas liquid (MMcf) 5,717 1,816 3,901 215 % Total (MBoe)(2) 2,099 706 1,393 197 % Average daily production volume: Oil (Bbls/d) 6,326 2,227 4,099 184 % Natural gas and natural gas liquids (Mcf/d) 31,586 10,033 21,553 215 % Total (Boe/d) 11,596 3,899 7,697 197 %



(1) Average prices shown in the table reflect prices both before and after the

effects of our realized commodity hedging transactions. Our calculation of

such effects includes both realized gains and losses on cash settlements for

commodity derivative transactions and premiums paid or received on options

that settled during the period.

(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based

on an approximate energy equivalency. This is an energy content correlation

and does not reflect a value or price relationship between the commodities.

The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship between our average realized natural gas price as a percentage of the average NYMEX price for the years 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) $ 93.94$ 86.73 Average NYMEX ($/Bbl) $ 99.46$ 92.56 Differential to NYMEX $ (5.52 )$ (5.83 ) Average realized oil price to NYMEX percentage 94 %



94 %

Average realized natural gas price ($/Mcf) $ 5.68 $

4.34 Average NYMEX ($/Mcf) $ 5.08$ 3.76 Differential to NYMEX $ 0.60$ 0.58



Average realized natural gas to NYMEX percentage 112 %

115 % 36

-------------------------------------------------------------------------------- Oil revenues increased 208% from $35.0 million during the six months ended June 30, 2013 to $107.6 million during the six months ended June 30, 2014. The increase is attributable to higher oil production volumes of 742 MBbls in conjunction with an increase in average oil prices to $93.94 per barrel from $86.73 per barrel. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $64.4 million while increases in oil prices accounted for a positive change of $8.3 million. Natural gas and NGLs revenues increased 312% from $7.9 million during the six months ended June 30, 2013 to $32.5 million during the six months ended June 30, 2014. The revenue increase is primarily a result of an increase in volumes sold of 3,901 MMcf in conjunction with an increase in average natural gas prices to $5.68 per Mcf from $5.29 per Mcf. Of the overall changes in natural gas and NGLs, increases in natural gas and NGLs production volumes accounted for a positive change of $16.9 million while increases in prices accounted for a positive change of $7.7 million. Natural gas revenue includes revenue from the sale of NGLs volumes. Operating Expenses. The following table summarizes our expenses for the periods indicated: Six Months Ended June 30, 2014 2013 $ Change % Change Operating expenses (in thousands, except percentages): Lease operating expenses $ 16,686 7,106 9,580 135 % Production and ad valorem taxes 8,483 2,223 6,260 282 % Depreciation, depletion and amortization 38,838 8,279 30,559 369 % General and administrative expenses 14,564 4,197 10,367 247 % Incentive unit compensation 51,088 - 51,088 100 % Stock based compensation 294 - 294 100 % Accretion of asset retirement obligations 209 61 148 243 % Total operating expenses $ 130,162$ 21,866$ 108,296 495 % Expense per Boe: Lease operating expenses $ 7.95$ 10.07$ (2.12 ) (21 )% Production and ad valorem taxes 4.04 3.15 0.89 28 % Depreciation, depletion and amortization 18.50 11.73 6.77 58 % General and administrative expenses 6.94 5.95 0.99 17 % Incentive unit compensation 24.34 - 24.34 100 % Stock based compensation 0.14 - 0.14 100 % Accretion of asset retirement obligations 0.10 0.09 0.01 11 %



Total operating expenses per Boe $ 62.01$ 30.99$ 31.02

100 % Lease Operating Expenses. Lease operating expenses increased 135% from $7.1 million during the six months ended June 30, 2013 to $16.7 million during the six months ended June 30, 2014. The increase is primarily due to the higher operated well count in the six month period ended June 30, 2014 as compared to the prior year period. On a per Boe basis, lease operating expenses decreased from $10.07 per Boe to $7.95 per Boe. This decrease was attributable to higher initial production from new wells which lower our average price, partially offset by an increase in costs for repairs and maintenance and additional lease operators. Production and Ad Valorem Taxes. Production and ad valorem taxes increased $6.3 million from $2.2 million during the six months ended June 30, 2013 to $8.5 million during the six months ended June 30, 2014 due to increased wellhead revenue resulting from higher production. Our increased drilling activity led to a higher number of wells brought on production during the six months ended June 30, 2014 compared to the six months ended June 30, 2013.



Depreciation, Depletion and Amortization. DD&A expense increased by $30.6 million from $8.3 million during the six months ended June 30, 2013 to $38.8 million for the six months ended June 30, 2014 due to an increase in capitalized costs and production volumes. DD&A expense per BOE increased by $6.77 primarily due to the increase in developmental costs and leasehold acquisitions.

General and Administrative Expenses. General and administrative expenses increased $10.4 million from $4.2 million during the six months ended June 30, 2013 to $14.6 million during the six months ended June 30, 2014 primarily due to higher payroll and payroll-related costs as we added additional employees to manage our growing asset base, higher rig count and increased production. 37 --------------------------------------------------------------------------------



Incentive unit compensation. Incentive unit compensation increased $51.1 million during the six months ended June 30, 2014 primarily due to the one time incentive unit compensation expense recognized upon the Corporate Reorganization.

Stock based compensation. Stock based compensation increased $0.3 million for the six months ended June 30, 2014 due to the issuance and amortization of the restricted stock and restricted stock units issued on May 29, 2014. No stock based compensation expenses were incurred during the six months ended June 30, 2013.



Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

Six Months Ended June 30, 2014 2013 $ Change % Change Other income (expense) (in thousands, except percentages): Interest expense, net $ (17,834 )$ (5,504 )$ (12,330 ) 224 % Prepayment premium paid on extinguishment of debt (5,107 ) - (5,107 ) 100 % Income (loss) from equity investment (59 ) 213 (272 ) (128 )% Derivative loss (20,029 ) (3,380 ) (16,649 ) 493 % Other income (expense) (5 ) 69 (74 ) (107 )% Total other expense, net $ (43,034 )$ (8,602 )$ (34,432 ) 400 % Interest Expense. Interest expense increased $12.3 million from $5.5 million during the six months ended June 30, 2013 to $17.8 million in the six months ended June 30, 2014 primarily due to higher weighted-average outstanding borrowings under our credit facilities and accrued interest under our Senior Notes due 2022.



Prepayment Premium on Extinguishment of Debt. During the first quarter of 2014, we incurred a $5.1 million charge related to a premium penalty on our then outstanding second lien term loan.

Derivative Loss. Loss on derivative instruments increased $16.6 million from $3.4 million during the six months ended June 30, 2013 to $20.0 million during the six months ended June 30, 2014 primarily as a result of the impact of unfavorable commodity price changes on increased hedging activities. Income Tax Expense Our operations are taxed at a combined U.S. federal and state effective tax rate of 35.7%. As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was not subject to U.S. federal income tax. During the six months ended June 30, 2014, we recognized $2.3 million of expense, an increase of $1.7 million, or 243%, as compared to the $0.7 million we recognized during the six months ended June 30, 2013. This increase was attributable to our status as a corporation subject to U.S. federal income tax as well as a net increase in operating income, the components of which are discussed above.



Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our revolving credit facility. Depending upon market conditions and other factors, we may also have the ability to issue additional equity and debt if needed. A portion of the net proceeds, of approximately $868.5 million, from the Offering were used to make a cash payment in settlement of the 9.5% return on the capital invested by NGP and PSP Members (the "Preferred Return"), and to reduce amounts drawn under our revolving credit facility. Remaining net proceeds are being used to fund a portion of our exploration and development program. Our primary use of capital is for the development and exploration of oil and natural gas properties and increasing our acreage position. Our borrowings were approximately $558.5 million and $430.0 million as of June 30, 2014 and December 31, 2013, respectively. Total borrowings during those periods were used primarily to fund development and exploration of oil and natural gas properties in addition to adding to our leasehold interests. 38 --------------------------------------------------------------------------------



Capital Requirements and Sources of Liquidity

In the six months ended June 30, 2014, we have spent $194.3 million for drilling and completing wells. During the year ended December 31, 2013, our aggregate drilling and completion capital expenditures were $268.4 million, excluding acquisitions. Substantially all of our remaining capital expenditures in 2014 for drilling and completion will be spent in the Midland Basin. However, the amount and timing of our remaining 2014 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. Based upon current oil and natural gas price expectations for 2014, we believe that our cash flow from operations, proceeds of our Offering and borrowings under our revolving credit facility will be sufficient to fund our operations through 2014. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. For example we expect a portion of our future capital expenditures to be financed with cash flows from operations derived from wells drilled in drilling locations not associated with proved reserves on our December 31, 2013 reserve report. The failure to achieve anticipated production and cash flows from operations from such wells could result in a reduction in future capital spending. Further, our capital expenditure budget for 2014 does not allocate any amounts for acquisitions of leasehold interests and proved properties. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. Cash Flows



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

Six Months Ended June 30, 2014 2013



Net cash provided by operating activities $ 53,593$ 27,768

Net cash used in investing activities (527,698 )



(96,184 )

Net cash provided by financing activities 978,231 69,861

Cash Flow Provided by Operating Activities. Net cash provided by operating activities was approximately $53.6 million and $27.8 million for the six months ended June 30, 2014 and 2013, respectively. Net cash provided by operating activities increased from the period ending June 30, 2013 to June 30, 2014 primarily due to the increase in oil and natural gas revenues, partially offset by the increase in derivative losses and the increase in lease operating expenses, production taxes, and other operating expenses. Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes. Our production volumes in the future will in large part be dependent upon the dollar amount and results of future capital expenditures. Future levels of capital expenditures made by us may vary due to many factors, including drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired. Cash Flow Used in Investing Activities. Net cash used in investing activities was approximately $527.7 million and $96.2 million for the six months ended June 30, 2014 and 2013, respectively. The increased amount of cash used in investing activities in the six months ended June 30, 2014 as compared to the six months ended June 30, 2013 was due to additional rigs operating, drilling higher working interest wells, and acquisition activity during the six months ended June 30, 2014 over the six months ended June 30, 2013. Cash Flow Provided by Financing Activities. Net cash provided by financing activities was approximately $978.2 million and $69.9 million for the six months ended June 30, 2014 and 2013, respectively. Net cash provided by financing activities increased in the period ending June 30, 2014 primarily due to the issuance of Class A Common Stock in conjunction with the Offering and Corporate Reorganization and the increase in long-term borrowings. 39 -------------------------------------------------------------------------------- Revolving Credit Facility. The Revolving Credit Agreement provided for an initial borrowing base of $175.0 million based on the Company's proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base will be redetermined by the lenders at least semi-annually on each April 1 and October 1, with the next redetermination to occur on October 1, 2014. As of June 30, 2014, the borrowing base was $327.5 million. There were no borrowings outstanding and $0.3 million in letters of credit outstanding as of June 30, 2014, resulting in availability of $327.2 million. Our revolving credit facility is secured by liens on substantially all of our properties and guarantees from our subsidiaries. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things:



- incur additional indebtedness;

- sell assets; - make loans to others; - make investments; - enter into mergers; - make or declare dividends;



- hedge future production or interest rates;

- incur liens; and

- engage in certain other transactions without the prior consent of the lenders.

The Revolving Credit Agreement requires the Company to maintain the following two financial ratios:

- a current ratio, which is the ratio of consolidated current assets (including

unused availability under its revolving credit facility) to consolidated

current liabilities of not less than 1.0 to 1.0 as of the last day of any

fiscal quarter

- a minimum interest coverage ratio, which is the ratio of EBITDAX to interest

expense, of not less than 2.5 to 1.0 as of the last day of any fiscal quarter

for the four fiscal quarters ending on such date.

The Revolving Credit Agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

At June 30, 2014, the Company was in compliance with all required covenants.

Senior Unsecured Notes. See Note 8-Debt to our Condensed and Consolidated Financial Statements included elsewhere in this Quarterly Report on Form 10-Q for a description of our 7.500% Senior Notes due 2022.

Derivative Activity. We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to continue our historical practice of entering into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering a portion of our projected oil production over a two-to-three year period at a given point in time. Working Capital Our working capital totaled $455.2 million and $(54.2) million at June 30, 2014 and December 31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $523.5 million and $19.4 million at June 30, 2014 and December 31, 2013, respectively. The $504.1 million increase in cash is primarily attributable to the receipt of proceeds for the sale of Class A Common Stock in conjunction with the Offering. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs. We expect that our pace of development, 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. 40 --------------------------------------------------------------------------------



Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our condensed consolidated and combined financial statements. See below for an expanded discussion of our significant accounting policies and estimates made by management.



Successful Efforts Method of Accounting for Oil and Natural Gas Activities

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The provision for DD&A of oil and natural gas properties is calculated on a reservoir basis using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in our Condensed Consolidated and Combined Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Future Development Costs Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development costs on an annual basis. 41

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Asset Retirement Obligations We have significant obligations to remove tangible equipment and facilities associated with our oil and gas wells and our gathering systems, and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are associated with plugging and abandoning wells and our gathering systems. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.



Allocation of Purchase Price in Business Combinations

As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.



Off-Balance Sheet Arrangements

As of June 30, 2014, we have no off-balance sheet arrangements.

42



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