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Arex Q3 2015 Earnings Report

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Third Quarter 2015 Results NOVEMBER 4, 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. Third Quarter 2015 Results – November 2015 2


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Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $630MM High-quality reserve base 146 MMBoe proved reserves 66% Liquids, 38% oil $1.4 BN proved PV-10 Permian core operating area 142,000 gross (130,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~2,000 Identified HZ drilling locations targeting Wolfcamp A/B/C Capital program focused on flexibility and returns - Aligned capital spending with cash flow - Cost reductions improving drilling IRRs - With limited land obligations and no service contracts, capital spending program is largely discretionary Note: Proved reserves as of 12/31/2014 and acreage as of 9/30/2015. 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 $2.82 per share on 11/3/2015, plus net debt as of 9/30/2015. See “PV-10 (unaudited)” slide. Third Quarter 2015 Results – November 2015 3


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3Q15 Key highlights 3Q15 HIGHLIGHTS • Drilled 4 and completed 5 HZ wells 3Q15 SUMMARY RESULTS Production (MBoe/d) 16.6 % Oil • Continued improvement on already bestin-class cost structure • Increased 3Q15 production 17% YoY to 16.6 MBoe/d • Reduced cash operating cost 18% YoY to $10.45/Boe 32% % Total liquids 64% Average realized price ($/Boe) Average realized price, excluding commodity derivatives impact $ Average realized price, including commodity derivatives impact 22.26 30.62 Costs and expenses ($/Boe) LOE $ 5.04 1.77 Exploration 1.28 General and administrative 4.77 G&A – cash component 3.65 G&A – noncash component • Reduced LOE 14% YoY to $5.04/Boe Production and ad valorem taxes 1.12 DD&A 20.47 Note: See “Cash operating expenses” slide. Third Quarter 2015 Results – November 2015 4


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3Q15 Operating highlights OPERATING HIGHLIGHTS Delivering Production Growth • Record total quarterly production of 16.6 MBoe/d (up 10% QoQ) • Quarterly oil production of 5.3 MBbl/d Maximizing Returns • LOE of $5.04/Boe, improved 14% YoY • Implemented further cost saving initiatives which should lower LOE and G&A by $5 $7MM annually starting FY2016 • 3Q15 Cash operating costs totaled $10.45/Boe, an 18% decrease compared to 3Q14 and a 5% improvement over 2Q15 Tracking Development Plan • Drilled 4 HZ wells and completed 5 HZ wells, with 4 wells currently waiting on completion • Wolfcamp B – 3 wells and Wolfcamp C – 2 wells • 3Q15 HZ Wolfcamp average IP 931 Boe/d (65% oil, 84% liquids) Note: See “Cash operating expenses” slide. Third Quarter 2015 Results – November 2015 5


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3Q15 Financial highlights FINANCIAL HIGHLIGHTS Continued Focus on Cutting Costs • Revenues (pre-hedge) of $33.9 MM, $46.7 MM with hedges • Adjusted net loss (non-GAAP) of $5.9 MM, or $0.14 per diluted share • Every per-unit cash cost metric has improved by double-digits since 3Q14 Preserving Cash Flow • Quarterly EBITDAX (non-GAAP) of $30.7 MM, or $0.76 per diluted share • Capital expenditures of $19.8 MM ($17.9 MM for D&C) • Remain well-hedged for the balance of 2015, added 2016 gas hedges Stable Financial Position • Liquidity of $172MM at September 30th • Following recent Fall 2015 redetermination, lender commitments and borrowing base set at $450 MM Note: See “Adjusted Net Income,” “EBITDAX,” and “Strong, Simple Balance Sheet” slides. Third Quarter 2015 Results – November 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 $13.02 $7.36 $7.00 $6.65 $6.18 $6.00 $12.0 $5.87 $5.55 $10.0 $4.97 $5.00 $9.12 $5.04 $8.90 $8.12 $8.0 $7.59 $7.51 $7.30 $4.00 $6.90 $6.84 $6.18 $6.0 $5.04 $3.00 $4.0 $2.00 $2.0 $1.00 $0.00 $0.0 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 Permian Peer D&C Cost ($ MM) AREX D&C Historical Track Record ($ MM) $9.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX $9.0 $8.6 $8.3 $8.0 $8.0 $7.8 $7.0 $7.0 $7.0 $5.8 $6.0 $5.5 $5.0 $6.6 $6.6 $6.5 $6.3 $6.0 $4.5 $4.2 $4.0 $6.1 $6.1 $5.0 $6.0 $5.8 $4.5 $4.0 $3.0 $3.0 $2.0 $2.0 $1.0 $1.0 $0.0 2011 2012 2013 2014 Current 3Q15 Best Well $0.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 AREX Source: Company presentations and public filings, peer data as of 2Q15. Peers include CPE, CWEI, CXO, EGN, FANG, LPI, MTDR, PE, PXD, and RSPP. Third Quarter 2015 Results – November 2015 7


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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 Third Quarter 2015 Results – November 2015 8


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Strong, simple balance sheet • Following the Fall 2015 redetermination, we had a $1 billion senior secured revolving credit facility in place, with aggregate lender commitments and borrowing base of $450 MM AREX Liquidity and Capitalization AREX Capitalization as of 9/30/2015 ($ MM) 275.6 240.0 $515.6 611.9 $1,127.5 Credit Facility 7.0% Senior Notes due 2021 Total Long-Term Debt 1 Shareholders’ Equity Total Book Capitalization • Current liquidity of $172 MM is more than adequate given capital budget is aligned with cash flow • LTM EBITDAX / LTM Interest of 5.8x, well above minimum 2.5x covenant requirement $0.3 Cash 1. Long-term debt is net of debt issuance costs of $7.4 million as of September 30, 2015 AREX Liquidity as of 9/30/2015 • Current ratio of 4.2x, well above minimum 1.0x covenant requirement • No near-term debt maturities $450.0 0.3 (278.0) (0.3) $172.0 Borrowing Base Cash and Cash Equivalents Borrowings under Credit Facility Undrawn Letters of Credit Liquidity AREX Debt Maturity Schedule ($ MM) $450.0 $400.0 $172 MM undrawn borrowing capacity $350.0 $300.0 7.0% Senior Notes $250.0 $200.0 $150.0 $278.0 $245.0 $100.0 $50.0 $0.0 2015 2016 2017 2018 2019 2020 2021 Third Quarter 2015 Results – November 2015 9


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D&C Cost reductions will significantly improve profitability 90% $3.5MM D&C 80% $4.0MM D&C 70% $4.5MM D&C IRR (%) 60% 50% 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. Third Quarter 2015 Results – November 2015 10


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Current hedge position • Based on the midpoint of current 2015 guidance, approximately 88% of forecasted 4Q15 oil production and 34% of forecasted natural gas production are hedged at weighted average floor prices of $74.78/Bbl and $4.06/MMBtu, respectively. Commodity & Period Contract Type Volume Contract Price Crude Oil October 2015 – December 2015 Collar 1,600 Bbls/d $84.00/Bbl - $91.00/Bbl October 2015 – December 2015 Collar 1,000 Bbls/d $90.00/Bbl - $102.50/Bbl October 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $94.00/Bbl October 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $95.00/Bbl October 2015 – December 2016 Swap 750 Bbls/d $62.52/Bbl Natural Gas October 2015 – December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu October 2015 – December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu - $4.25/MMBtu March 2016 – December 2016 Swap 200,000 MMBtu/month $2.93/MMBtu Third Quarter 2015 Results – November 2015 11


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Production and expense guidance 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 Third Quarter 2015 Results – November 2015 12


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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 nine months ended September 30, 2015 and 2014. (in thousands, except per-share amounts) Net (loss) income Adjustments for certain items: Unrealized (gain) loss on commodity derivatives Rig termination fees Impairment of oil and gas properties Termination costs Gain on debt extinguishment Related income tax effect Adjusted net (loss) income Adjusted net (loss) income per diluted share $ $ $ Three Months Ended September 30, 2015 2014 (148,787) $ 22,447 (296) 1,701 220,197 1,436 (1,483) (78,623) (5,855) (0.14) $ $ (18,810) 6,816 10,453 0.27 $ $ $ Nine Months Ended September 30, 2015 2014 (168,345) $ 29,185 22,929 2,199 220,197 1,436 (1,483) (86,926) (9,993) (0.25) $ $ (5,206) 1,886 25,865 0.66 Third Quarter 2015 Results – November 2015 14


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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 nine months ended September 30, 2015 and 2014. (in thousands, except per-share amounts) Net (loss) income Exploration Depletion, depreciation and amortization Share-based compensation Impairment of oil and gas properties Unrealized (gain) loss on commodity derivatives Gain on debt extinguishment Termination costs Interest expense, net Income tax (benefit) provision EBITDAX EBITDAX per diluted share $ $ $ Three Months Ended September 30, 2015 2014 (148,787) $ 22,447 1,956 891 31,222 25,959 1,708 1,965 220,197 (296) (18,810) (1,483) 1,436 6,465 5,442 (81,756) 12,756 30,662 $ 50,650 0.76 $ 1.29 $ $ $ Nine Months Ended September 30, 2015 2014 (168,345) $ 29,185 4,211 3,595 86,146 78,138 6,000 5,726 220,197 22,929 (5,206) (1,483) 1,436 18,630 15,936 (93,121) 16,590 96,600 $ 143,964 2.39 $ 3.66 Third Quarter 2015 Results – November 2015 15


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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, (3) share-based compensation expense, (4) termination costs, and (5) impairment of oil and gas properties. 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 nine months ended September 30, 2015 and 2014. (in thousands, except per-Boe amounts) Operating expenses Exploration Depletion, depreciation and amortization Share-based compensation Termination costs Impairment of oil and gas properties Cash operating expenses Cash operating expenses per Boe $ $ $ Three Months Ended September 30, 2015 2014 272,462 $ 45,525 (1,956) (891) (31,222) (25,959) (1,708) (1,965) (1,436) (220,197) 15,943 $ 16,710 10.45 $ 12.79 $ $ $ Nine Months Ended September 30, 2015 2014 365,118 $ 141,236 (4,211) (3,595) (86,146) (78,138) (6,000) (5,726) (1,436) (220,197) 47,128 $ 53,777 11.21 $ 14.70 Third Quarter 2015 Results – November 2015 16


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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. Third Quarter 2015 Results – November 2015 17


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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 Third Quarter 2015 Results – November 2015 18


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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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