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Arex Q2 2015 Earnings Report

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Second Quarter 2015 Results AUGUST 5, 2015


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Forward-looking statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company’s Wolfcamp shale resource play, estimated resource potential and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, type curve, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words “will,” “potential,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “target,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Cautionary statements regarding oil & gas quantities The Securities and Exchange Commission (“SEC”) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. EUR estimates, identified drilling locations and resource potential estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interest may differ substantially from the Company’s estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Company’s drilling project, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per well EUR and resource potential may change significantly as development of the Company’s oil and gas assets provides additional data. Type/decline curves, estimated EURs, resource potential, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. The Company has limited production experience with this project, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, IRR estimates are before taxes and assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. Second Quarter 2015 Results – August 2015 2


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Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $671MM High-quality reserve base 146 MMBoe proved reserves 66% Liquids, 38% oil $1.4 BN proved PV-10 Permian core operating area 143,000 gross (130,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~2,000 Identified HZ drilling locations targeting Wolfcamp A/B/C 2015 Capital program focused on flexibility and returns - Running an average of 1 HZ rig in the Wolfcamp shale play with a reduced capital budget of approximately $150 MM - Completed drilling activities and commitments ahead of schedule - Deferred three completions to post-2015 Note: Proved reserves as of 12/31/2014 and acreage as of 6/30/2015. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing share price of $4.25 per share on 7/29/2015, plus net debt as of 6/30/2015. See “PV-10 (unaudited)” slide. Second Quarter 2015 Results – August 2015 3


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2Q15 Key highlights 2Q15 HIGHLIGHTS • Drilled 9 and completed 10 HZ wells 2Q15 SUMMARY RESULTS Production (MBoe/d) 15.3 % Oil • Continued improvement on already bestin-class HZ well costs • Increased 2Q15 production 8% YoY to 15.3 MBoe/d • Reduced cash operating cost 26% YoY to $11.02/Boe 36% % Total liquids 65% Average realized price ($/Boe) Average realized price, excluding commodity derivatives impact $ Average realized price, including commodity derivatives impact 27.76 34.44 Costs and expenses ($/Boe) LOE $ 4.97 2.14 Exploration 0.84 General and administrative 5.40 G&A – cash component 3.91 G&A – noncash component • Reduced LOE 20% YoY to $4.97/Boe Production and ad valorem taxes 1.49 DD&A 20.43 Note: See “Cash operating expenses” slide. Second Quarter 2015 Results – August 2015 4


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2Q15 Operating highlights OPERATING HIGHLIGHTS Delivering Production Growth Maximizing Returns Tracking Development Plan • Total record quarterly production 15.3 MBoe/d (up 8% QoQ) • Oil production 499 MBbl (up 1% QoQ) • Successfully implemented cost reduction initiatives, current HZ well costs now averaging $4.5 MM per well, down 15+% from 2014 average of $5.5 MM • D&C cost savings includes $450,000 per well of permanent savings from water recycling • LOE of $4.97/Boe, improved 20% YoY • Drilled 9 HZ wells and completed 10 HZ wells, with 2 additional wells in final stages of completion • Wolfcamp B – 5 wells and Wolfcamp C – 5 wells • 2Q15 HZ Wolfcamp average IP 869 Boe/d (58% oil, 81% liquids) Second Quarter 2015 Results – August 2015 5


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2Q15 Financial highlights FINANCIAL HIGHLIGHTS • • Heightened Focus on Cutting • Costs • Preserving Cash Flow Stable Financial Position • • • • Revenues (pre-hedge) of $38.6 MM, $47.9 MM with hedges Adjusted net loss (non-GAAP) of $2.8 MM, or $0.07 per diluted share Every per-unit cash cost metric has improved since 2Q14 2Q15 Cash operating costs totaled $11.02/Boe, a 26% decrease compared to 2Q14 and an 11% improvement over 1Q15 Quarterly EBITDAX (non-GAAP) of $32.6 MM, or $0.80 per diluted share Capital expenditures of $56.9 MM ($53.5 MM for D&C) Remain well-hedged for the balance of 2015, added 2016 oil hedges Reduced 2015 capex from $160 MM to $150 MM • Liquidity of $193MM at June 30th • Lenders reaffirmed $450 MM commitment amount following Spring 2015 redetermination Note: See “Adjusted Net Income,” “EBITDAX,” “Strong, Simple Balance Sheet, and “Cash operating expenses” slides. Second Quarter 2015 Results – August 2015 6


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Lowest cost structure in the Permian Basin Permian Peer LOE ($/Boe) AREX LOE Historical Track Record ($/Boe) $8.00 $14.0 $7.36 $7.00 $6.65 $6.18 $6.00 $13.26 $12.0 $11.23 $5.87 $5.55 $10.0 $9.63 $9.03 $4.97 $5.00 $8.78 $8.14 $8.0 $7.83 $7.58 $4.00 $6.0 $4.97 $3.00 $4.0 $2.00 $2.0 $1.00 $0.00 $0.0 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 $6.1 AREX $6.0 Permian Peer D&C Cost ($ MM) AREX D&C Historical Track Record ($ MM) $9.0 Peer 1 $9.0 $8.6 $8.0 $8.5 $8.0 $7.0 $7.0 $5.8 $6.0 $7.0 $7.0 $6.5 $6.3 $6.3 $6.0 $5.5 $5.0 $6.6 $4.5 $5.0 $4.5 $4.3 $4.0 $4.0 $3.0 $3.0 $2.0 $2.0 $1.0 $1.0 $0.0 $0.0 2011 2012 2013 2014 Current 2Q15 Best Well Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 AREX Source: Company presentations and public filings, peer data as of 1Q15. Peers include CPE, CWEI, EGN, FANG, LPI, PE, PXD, and RSPP. Second Quarter 2015 Results – August 2015 7


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63,000 BBL Treated Water Tank 44,000 BBL Treated Water Tank 90 BPM Pump Station Water Treatment & Filtration Facility Skim Oil Sales 32,000 BBL Dirty Water Tank Flowback & Produced Water Offloading Terminal & Separation Facility 20” Treated Flowback & Produced Frac Water Supply Line 63,000 BBL Treated Water Tank 63,000 BBL Treated Water Tank N 32,000 BBL Treated Water Tank 8” Flowback & Produced Saltwater Line 32,000 BBL Treated Water Tank 8” Low Chloride Treated Frac Water Supply Line AREX Flowback and Produced Water Recycle Facility • 2 MM Bbls flowback and produced water recycled since inception 32,000 BBL Treated Water Tank Flowback & Produced Water Supply Second Quarter 2015 Results – August 2015 8


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Strong, simple balance sheet • At June 30, 2015, we had a $1 billion senior secured revolving credit facility in place, with aggregate lender commitments of $450 MM and borrowing base of $525 MM AREX Liquidity and Capitalization AREX Capitalization as of 6/30/2015 ($ MM) $0.8 Cash • Following the Spring 2015 redetermination, our lenders reaffirmed the commitment amount of $450 MM, while reducing the borrowing base to $525 MM • 254.4 244.7 $499.1 758.9 $1,258.0 Credit Facility 7.0% Senior Notes due 2021 Total Long-Term Debt 1 Shareholders’ Equity Total Book Capitalization A $75 MM cushion remains against more conservative bank lending framework 1. Long-term debt is net of debt issuance costs of $7.9 million as of June 30, 2015 • Manageable Debt / LTM EBITDAX of 3.1x AREX Liquidity as of 6/30/2015 • LTM EBITDAX / LTM Interest of 6.9x, well above minimum 2.5x covenant requirement • No near-term debt maturities $450.0 0.8 (257.0) (0.3) $193.4 Aggregate Commitment Cash and Cash Equivalents Borrowings under Credit Facility Undrawn Letters of Credit Liquidity AREX Debt Maturity Schedule ($ MM) $450.0 $400.0 $350.0 $193 MM undrawn borrowing capacity $300.0 7.0% Senior Notes $250.0 $200.0 $150.0 $257.0 $250.0 $100.0 $50.0 $0.0 2015 2016 2017 2018 2019 2020 2021 Second Quarter 2015 Results – August 2015 9


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Valuation and leverage well supported by proved reserve base • 12/31/2014 reserve summary prepared by DeGolyer and MacNaughton • Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per Boe1 • Total proved reserves up 27% YoY, proved oil reserves up 20% YoY • PV-10 up 25% YoY to a record $1.4 billion Total Proved Reserves Proved PV-10 Reserves by Commodity 34% 40% 38% 38% 59% 62% < 1% 1% 28% PDP PDNP PUD Oil Oil (MBbls) NGLs NGLs (MBbls) Natural Gas PDP Natural Gas (MMcf) Total (MBoe) PDNP PUD PV-10 ($ MM) 2 17,599 18,319 133,583 58,181 $870.0 379 763 5,378 2,039 $12.4 PUD 37,360 21,825 161,059 86,028 $530.6 Total Proved 55,338 40,907 300,020 146,248 $1,413.0 PDP PDNP 1. Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year. 2. PV-10 calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and natural gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas. Second Quarter 2015 Results – August 2015 10


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D&C Cost reductions will significantly improve profitability 70% $4.0MM D&C $4.5MM D&C 60% $5.0MM D&C 50% IRR (%) 40% 30% 20% 10% 0% $40 $50 $60 $70 $80 $90 Realized Oil Price ($/Bbl) Note: HZ Wolfcamp economics assume $4.00/Mcf realized natural gas price and NGL price based on 40% of realized oil price. Second Quarter 2015 Results – August 2015 11


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Established infrastructure in place is critical to low cost structure Reagan Irion Pangea West Crockett Schleicher Recently completed water recycling facility 329,000 Bbl Capacity North & Central Pangea Benefits of water recycling • Reduce D&C cost • Reduce LOE • Increase project profit margin • Minimize fresh water use, truck traffic and surface disturbance South Pangea Sutton Second Quarter 2015 Results – August 2015 12


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Current hedge position • Based on the midpoint of updated 2015 guidance, approximately 85% of forecasted 3Q15-4Q15 oil production and 32% of forecasted natural gas production are hedged at weighted average floor prices of $75.93/Bbl and $4.06/MMBtu, respectively. Commodity & Period Contract Type Volume Contract Price Crude Oil July 2015 – December 2015 Collar 1,600 Bbls/d $84.00/Bbl - $91.00/Bbl July 2015 – December 2015 Collar 1,000 Bbls/d $90.00/Bbl - $102.50/Bbl July 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $94.00/Bbl July 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $95.00/Bbl July 2015 – December 2016 Swap 750 Bbls/d $62.52/Bbl Natural Gas July 2015 – December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu July 2015 – December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu - $4.25/MMBtu Second Quarter 2015 Results – August 2015 13


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Production and expense guidance Updated 2015 Guidance Production Oil (MBbls) 1,900 – 1,975 NGLs (MBbls) 1,575 – 1,625 Natural Gas (MMcf) Total (MBoe) 11,550 – 11,700 5,400 – 5,550 Operating costs and expenses (per Boe) Lease operating $5.50 - $6.50 Production and ad valorem taxes 7.50% of oil & gas revenues Cash general and administrative $3.75 - $4.25 Exploration (non-cash) $0.50 - $1.00 Depletion, depreciation and amortization Capital expenditures (in millions) $20.00 - $22.00 ~$150 Second Quarter 2015 Results – August 2015 14


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Appendix


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Adjusted net (loss) income (unaudited) ADJUSTED NET (LOSS) INCOME (UNAUDITED) The amounts included in the calculation of adjusted net (loss) income and adjusted net (loss) income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following table provides a reconciliation of adjusted net (loss) income to net (loss) income for the three and six months ended June 30, 2015 and 2014. (in thousands, except per-share amounts) Net (loss) income Adjustments for certain items: Unrealized loss on commodity derivatives Rig termination fees Related income tax effect Adjusted net (loss) income Adjusted net (loss) income per diluted share Three Months Ended June 30, 2015 2014 $ (11,850) $ 3,793 $ $ 13,904 (4,866) (2,812) (0.07) $ $ 7,678 (2,780) 8,691 0.22 $ $ $ Six Months Ended June 30, 2015 2014 (19,558) $ 6,738 23,225 498 (8,303) (4,138) (0.10) $ $ 13,604 (4,934) 15,408 0.39 Second Quarter 2015 Results – August 2015 16


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EBITDAX (unaudited) EBITDAX (UNAUDITED) The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is not a measure of net income or cash flow as determined by GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following table provides a reconciliation of EBITDAX to net (loss) income for the three and six months ended June 30, 2015 and 2014. (in thousands, except per-share amounts) Net (loss) income Exploration Depletion, depreciation and amortization Share-based compensation Unrealized loss on commodity derivatives Interest expense, net Income tax (benefit) provision EBITDAX EBITDAX per diluted share $ $ $ Three Months Ended June 30, 2015 2014 (11,850) $ 3,793 1,165 1,966 28,404 28,573 2,075 1,107 13,904 7,678 6,243 5,357 (7,369) 2,153 32,572 $ 50,627 0.80 $ 1.29 $ $ $ Six Months Ended June 30, 2015 2014 (19,558) $ 6,738 2,255 2,704 54,924 52,179 4,292 3,761 23,225 13,604 12,165 10,494 (11,365) 3,834 65,938 $ 93,314 1.63 $ 2.37 Second Quarter 2015 Results – August 2015 17


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Cash operating expenses Cash operating expenses We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense and (3) share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Company’s ability to manage its operating expenses and cash flows. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following table provides a reconciliation of cash operating expenses to operating expenses for the three and six months ended June 30, 2015 and 2014. (in thousands, except per-Boe amounts) Operating expenses Exploration Depletion, depreciation and amortization Share-based compensation Cash operating expenses Cash operating expenses per Boe $ $ $ Three Months Ended June 30, 2015 2014 46,970 $ 50,812 (1,165) (1,966) (28,404) (28,573) (2,075) (1,107) 15,326 $ 19,166 11.02 $ 14.90 $ $ $ Six Months Ended June 30, 2015 2014 92,656 $ 95,711 (2,255) (2,704) (54,924) (52,179) (4,292) (3,761) 31,185 $ 37,067 11.65 $ 15.75 Second Quarter 2015 Results – August 2015 18


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F&D costs (unaudited) All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year. Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year. We believe that providing F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on February 26, 2015. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies. The following table reconciles our estimated F&D costs for 2014 to the information required by paragraphs 11 and 21 of ASC 932-235. F&D Cost reconciliation Cost summary (in thousands) Property acquisition costs Unproved properties $ 4,578 Proved properties - Exploration costs 3,831 Development costs Total costs incurred 382,995 $ 391,404 Reserves summary (MBoe) Balance – 12/31/2013 114,661 Extensions & discoveries 43,247 Production (1) (5,281) Revisions to previous estimates (6,379) Balance – 12/31/2014 146,248 F&D cost ($/Boe) All-in F&D cost $ Drill-bit F&D cost 10.62 8.94 Reserve replacement ratio Drill-bit 819% (1) Production includes 1,390 MMcf related to field fuel. Second Quarter 2015 Results – August 2015 19


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PV-10 (unaudited) The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $1.4 billion at December 31, 2014, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas. PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. (in millions) December 31, 2014 PV-10 $ 1,413 Less income taxes: Undiscounted future income taxes (1,267) 10% discount factor 910 Future discounted income taxes Standardized measure of discounted future net cash flows (357) $ 1,056 Second Quarter 2015 Results – August 2015 20


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Contact information SERGEI KRYLOV Executive Vice President & Chief Financial Officer 817.989.9000 ir@approachresources.com www.approachresources.com


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