Approach Resources Inc. JUNE 2013 Exhibit 99.1 INVESTOR PRESENTATION

Forward-Looking Statements 2 Cautionary Statements Regarding Oil & Gas Quantities 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. 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 ongoing drilling program, 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 very limited production experience with these projects, 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.

Company Overview • Enterprise value $1.2 BN • High quality reserve base 95.5 MMBoe proved reserves 99% Permian Basin • Permian core operating area 167,000 gross (148,000 net) acres 1+ BnBoe gross, unrisked resource potential 2,000+ Identified HZ drilling locations targeting the Wolfcamp A/B/C • 2013 capital program of $260 MM Running 3 HZ rigs in the Wolfcamp shale play Targeting 30%+ production growth 3 Notes: Proved reserves and acreage as of 12/31/2012 and 3/31/2013, respectively. 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 $25.39 per share on 6/7/2013, plus net debt as of 3/31/2013, pro forma for $250 MM senior notes offering. ASSET OVERVIEW AREX OVERVIEW

Key Investment Highlights • Low-Risk, Oil-Rich Asset Base • Oil and liquids-weighted asset base in Midland Basin 167,000 gross (148,000 net) primarily contiguous acres Proved reserves are 69% liquids; 1Q13 production is 69% liquids (41% oil) • High Degree of Operational Control • Operate 100% reserve base with ~100% working interest • Track Record of Growth at Competitive Cost • Reserve and production CAGR since 2004 of 32% and 35% respectively • Low-cost operator with competitive F&D and low lifting costs 3-year average drill-bit F&D cost of $7.95/Boe vs. peer median of $13.69/Boe¹ 1Q13 lease operating expense of $7.14/Boe vs. peer median of $9.42/Boe¹ • Prudent Financial Management • Substantial pro forma liquidity of $406 MM as of 3/31/13² • Capital budget will be fully funded through 2014 and beyond with operating cash flow, credit facility borrowings and proceeds from $250 MM senior notes offering • Active hedging program • Experienced Management • Over 150 years of combined industry experience for senior management team • Strong operational track record in Permian Basin • Significant technical expertise 4 Note: Estimated proved reserves and acreage as of 12/31/2012 and 3/31/2013, respectively. ¹ Peers include CXO, FANG, KOG, LPI, OAS, PXD, ROSE and SM; F&D cost is a non-GAAP financial measure. See “F&D Costs” slide in appendix for our calculation of F&D cost and reconciliation to the information required by paragraphs 11 and 21 of ASC 932-235. ² Pro forma for $250 MM senior notes offering and 5/1/2013 borrowing base increase. See “Liquidity” slide in appendix.

Extensive Inventory of Future Wolfcamp/Wolffork Drilling Locations 703 690 703 2,096 887 2,983 HZ Wolfcamp A HZ Wolfcamp B HZ Wolfcamp C Subtotal HZ Wolfcamp Vertical Wolffork Total Gross Resource Potential (MMBoe): 316 311 316 943 126 1,068 IDENTIFIED DRILLING LOCATIONS 5 Notes: Identified locations based on 120-acre spacing for HZ Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40-acre spacing for Vertical Wolffork Recompletions and 40-acre spacing for Vertical Canyon Wolffork. No Wolfcamp or Wolffork locations assigned to south Project Pangea.

Track Record of Reserve Growth… 6 • YE’12 reserves up 24% YoY • Replaced 1,346% of reserves at a drill-bit F&D cost of $7.45/Boe • 60.1 MMBoe proved reserves booked to Wolfcamp/Wolffork oil shale play • Strong organic reserve growth driven by oil from HZ Wolfcamp shale • Oil reserves up 7x since YE’09 • Oil reserves up 106% YoY PD Oil reserves up 60% YoY Launched Wolfcamp Study Announced Vertical Wolfcamp Pilot Results Began HZ Wolfcamp Pilot Program Strong HZ Wolfcamp Results; Prepare for Large-Scale Development RESERVE GROWTH OIL RESERVE GROWTH 100 120 80 60 40 20 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 Natural Gas (MMBoe) Oil & NGLs (MMbbls) Oil (MMBbls) 40 35 30 25 20 15 10 5 0 2009 2010 2011 2012

…and Production Growth… 7 • 2012 production increased 24% YoY • Targeting 30%+ production growth in 2013 • Strong organic production growth driven by oil from HZ Wolfcamp shale • Oil production up 4x since 2009 • Oil production up 101% over 2011 PRODUCTION GROWTH OIL PRODUCTION GROWTH 9.0 8.0 7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 2004 2005 2006 2007 2008 2009 2010 2011 2012 1200 1000 800 600 400 200 0 2009 2010 2011 2012 Natural Gas (MBoe/d) Oil & NGLs (Mbbls/d) Oil (MBbls)

…at Low-Cost Notes: Peer companies include CXO, FANG, KOG, LPI, PXD, ROSE and SM. 3-YR average F&D costs data based on SEC filings for twelve months ended December 31, 2012. F&D cost is a non-GAAP financial measure. See “F&D Costs” slide in appendix for our calculation of F&D cost and reconciliation to the information required by paragraphs 11 and 21 of ASC 932-235. Lease operating expense data based on SEC filings for three months ended March 31, 2013. 1Q13 LOE ($/Boe) 3-YR AVERAGE F&D COSTS ($/Boe) LEASE OPERATING EXPENSE ($/Boe) 8 2010-2012 Drill-Bit F&D Cost ($/Boe) $20.00 $18.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 Peer 1 AREX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 1 AREX Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 $7.11 $7.95 $9.59 $12.89 $13.44 $13.72 $14.80 $18.18 $19.76 $5.67 $7.14 $7.18 $7.74 $8.41 $9.35 $9.86 $12.61 $14.52

AREX Wolfcamp Oil Shale Resource Play 9 Plan to drill ~ 35 to 40 HZ wells with 3 rigs Testing “stacked-wellbore” development and optimizing well spacing and completion design Decrease well costs and increase efficiencies when field infrastructure projects are completed PERMIAN CORE OPERATING AREA 2013 OPERATIONS Large, primarily contiguous acreage position with oil-rich, multiple pay zones Large, primarily contiguous acreage position Oil-rich, multiple pay zones 167,000 gross (148,000 net) acres Low acreage cost ~$500 per acre 2,096 Identified HZ Wolfcamp locations targeting the Wolfcamp A, B & C 940+ MMBoe gross, unrisked HZ Wolfcamp resource potential

Wolfcamp Oil Shale Play 10 WOLFCAMP SHALE – WIDESPREAD, THICK, CONSISTENT & REPEATABLE

HZ Wolfcamp – 79% of IP is Oil 11 Source: Publicly available regulatory filings, company presentations.

Wolfcamp Stacked Pay Zones HZ WOLFCAMP TARGET Wolfcamp A Wolfcamp B Wolfcamp C Identified locations 703 690 703 EUR (MBoe) 450 450 450 Gross Resource Potential (MMBoe) 316 310 316 940+ MMBoe Total Gross Resource Potential HZ TARGETS & RESOURCE POTENTIAL Notes: Identified locations based on multi-bench development and 120-acre spacing. No locations assigned to south Project Pangea. 12 AREX Baker A 112 Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp Top GR API LLD OHMM 200 0.2 2,000 MSFL OHMM 0.2 2,000 0.3 -0.1 0.3 -0.1 DPHI 0.2 Free Hydrocarbon 0.2 0 BVW 20 200 20 200 NPHI 0 0 5500 5600 5700 5900 6000 6100 6200 6300 6400 6500 5800

13 X-Section View (heel to toe) Allows maximum volumes of shale reservoir to be fraced Multiple Lateral Stacking – Effective Frac Volumes A Bench B Bench C Bench 660’ 481’ 481’ CHEVRON STACKING DEVELOPMENT PATTERN

AREX HZ Wolfcamp Activity 14 Note: Acreage as of 3/31/2013. Schleicher Irion Reagan Sutton 54-9 1 54-2 1 54-9 2 54-12 1 54-15 1 54-15 2 54-16 3 55-21 2 54-19 3 54-8 1 54-13 1 56-6 1 56-15 1 PW 6601H PW 6602H CT L 1801 54-13 2 54-20 2 54-20 1 55-21 3 56-14 1 PW 6507H Childress 603 Childress G 1008 Davidson 3406 CT B 1601 CT M 901H Baker B 203 CT B 1303 45 C 803H ST 42-11 2R 45 E 1101H Baker C 1201 45 A 701H 45 B 2401H 45 F 2303H CT B 1308 42-23 9 Baker A 114 West 2308 42-14 10 42 A 2101H 45 D 902H CT A 807 45 A 703H 45 B 2402H CT J 1001 CT G 1001 CT H 1001 West A 2210 42-11 3 CT J 1003H 42 C 101H CT H 1002 CT G 701H 45 B 2403H 45 D 905H 45 A 704H CT K 1901 CT K 1902 45 D 904H 45 E 1102H Baker B 207H Baker B 206H CT H 1004H PW 6533H PW 6535H 45 F 2304H 45 A 706H 45A 708H 45A 710H 45A 712H Elliott 2002HB U 50 A 603HA CT M 902 Baker B 201 PW 6504H PW 6502H Elliott 2001HB 42-23 11 42-15 2 42 B 1001H Crockett CT M 934HB Pangea West North & Central Pangea South Pangea • 18,000 gross acres • Pad drilling with A/B and A/C “stacked” wellbores • 3-D seismic interpretation completed • HZ pilot wells WOC • 59,000 gross acres • Continuing completion design improvement • 89,000 gross acres • Pad drilling with A/B & A/C “stacked” laterals • Infrastructure 2Q’13 in North Pangea Õ D&C target cost $5.5 MM • 3-D seismic acquisition completed. Data processing in progress • Targeting HZ pilot well in 3Q’13 Chandler 4403 Lauffer 1306 Bailey 315 Legend Vertical Producer HZ Producer HZ – Waiting on Completion HZ – Drilling HZ – Permit

HZ Wolfcamp Well Performance 15 Time (Days) 0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 0 60 120 180 240 300 360 420 480 Daily Production Data from AREX Recent HZ Wells 450 MBoe Type Curve Daily Production Data from AREX HZ A Bench Wells B Bench well data (24 wells) Legend A Bench well data (3 wells) 450 MBoe Type Curve Recent B bench well data (7 wells) CONTINUED STRONG WELLS RESULTS – TRACKING ABOVE THE TYPE CURVE

AREX HZ Wolfcamp Economics 16 Notes: Identified locations based on multi-bench development and 120-acre spacing for HZ Wolfcamp. No locations assigned to south Project Pangea. Play Type Horizontal Wolfcamp Avg. EUR (gross) Targeted Well Cost Potential Locations Gross Resource Potential BTAX IRR SENSITIVITIES • Horizontal drilling improves recoveries and returns • Multiple, stacked horizontal targets • 7,000’+ lateral length • ~80% of EUR made up of oil and NGLs • 3 HZ rigs running in Project Pangea / Pangea West 80 70 60 50 40 30 20 10 0 $100 / bbl $90 / bbl $80 / bbl $70 / bbl 350 400 450 500 550 Well EUR (MBoe) 940+ MMBoe 2,096 $5.5 MM 450 MBoe

AREX Drilling Locations, Targets & Resource Potential 17 Notes: Potential locations based on 120-acre spacing for HZ Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40-acre spacing for Vertical Wolffork Recompletions and 40-acre spacing for Vertical Canyon Wolffork. No Wolfcamp or Wolffork locations assigned to south Project Pangea. TARGET DRLLING DEPTH (FT.) EUR (MBoe) IDENTIFIED LOCATIONS GROSS RESOURCE POTENTIAL Horizontal Wolfcamp Wolfcamp A 7,000+ (lateral length) 450 703 316,350 Wolfcamp B 7,000+ (lateral length) 450 690 310,500 Wolfcamp C 7,000+ (lateral length) 450 703 316,350 Total HZ 2,096 943,200 Vertical Wolffork Recompletions, Wolffork & Canyon Wolffork < 7,500 to < 8,500 93 to 193 887 124,594 1.1 BnBoe Total Gross Resource Potential Multiple Decades of HZ Drilling Inventory

Infrastructure for Large-Scale Development 18 • Reducing D&C Cost to $5.5 MM or lower • Reducing LOE • Minimizing truck traffic and surface disturbance • Increasing project profit margin Pangea West North & Central Pangea South Pangea Schleicher Crockett Irion Reagan Sutton

Infrastructure & Equipment Projects 19 • Safely and securely transport water across Project Pangea and Pangea West • Reduce time and money spent on water hauling and disposal and truck traffic • Expected savings from water transfer equipment ~$0.1 MM/HZ well • Expected savings from SWD system ~$0.45 MM/HZ well • Expected company-wide LOE savings ±$0.4 MM per month • Replace rental equipment and contractors with Company-owned and operated equipment and personnel; reduce money spent on flowback operations • Expected savings from flowback equipment ~$0.1 MM/HZ well • Expected LOE savings from gas lift system $6,300/HZ per month • Facilitate large-scale field development • Reduce fresh water use and water costs • Expected savings from non-potable water source ~$0.45 MM/HZ well • Efficiently transport crude oil to market and reduce inventory • Reduce oil transportation differential to an estimated $2.50/Bbl – $4.00/Bbl Purchasing and installing water transfer equipment Drilling and/or converting SWD wells Purchasing and installing flowback equipment Securing water supply Testing non-potable water and recycling flowback water Installing crude takeaway lines Purchased oil hauling trucks BENEFITS Infrastructure and equipment projects are key to large-scale field development and to reducing D&C costs as well as LOE cost PROJECTS

Financial Information NON-GAAP RECONCILIATIONS

2013 Capital Budget • 2013 Capital budget $260 MM, approx. 90% for HZ Wolfcamp • 3 HZ rigs in the Wolfcamp shale • Targeting 30%+ production growth Key takeaways: 21 • 2013 Production guidance 3.6 MMBoe – 3.9 MMBoe • 2013E Production mix 70% liquids 2013 capital program provides flexibility to develop Wolfcamp oil shale and monitor commodity prices and service costs Increase in oil production drives expected increase in cash flow Borrowing base increase to $315 MM and $250 MM senior notes offering strengthen liquidity • Targeting Wolfcamp A, B and C • Testing “stacked-wellbore” development • Optimizing well spacing and completion design

Strong, Simple Balance Sheet 22 FINANCIAL RESULTS ($MM) 3/31/13 Summary Balance Sheet Cash $0.6 $91.5 Revolver 152.3 – Senior Notes – 250.0 Total Debt $152.3 $250.0 Shareholders’ Equity 635.2 635.2 Total Book Capitalization $787.5 $885.2 Liquidity Borrowing Base $280.0 $315.0² Cash and Cash Equivalents 0.6 91.5 Outstandings and letters of credit (152.6) (0.3) Liquidity $128.0 $406.2 Key Metrics LTM EBITDAX $86.5 $86.5 Total Reserves (MMBoe) 95.5 95.5 Proved Developed Reserves (MMBoe) 32.8 32.8 % Proved Developed 34% 34% % Liquids 69% 69% Credit Statistics 4 Net Debt / Book Cap 20% Net Debt / 1Q13 Annualized EBITDAX 1.6x Net Debt / Proved Reserves ($/Boe) $1.66 Net Debt / Proved Developed Reserves ($/Boe) $4.83 Net Debt / Production ($/Boepd) $18,838 Notes: Estimated proved reserves as of 12/31/2012. See “Liquidity” slide in appendix. ¹ Pro forma for $250 MM senior notes offering and 05/1/2013 borrowing base increase. ² $315mm borrowing base under $500 MM facility. 3 EBITDAX is a non-GAAP financial measure. See “EBITDAX” slide in appendix for reconciliation to net income (loss). 4 Net debt is debt balance less available cash and letters of credit. 1 3/31/13 As Adj.

2013 Operating and Financial Guidance 23 2013 GUIDANCE 2013 Guidance Production Total (MBoe) 3,600 – 3,900 Percent Oil & NGLs 70% Operating costs and expenses ($/per Boe) Lease operating $ 7.00 – 8.00 Production and ad valorem taxes $ 3.00 – 4.50 Exploration $ 2.00 – 3.00 General and administrative $ 7.00 – 8.50 Depletion, depreciation and amortization $ 20.00 – 24.00 Capital expenditures ($MM) Approximately $260 • 2Q13 Production guidance 8.7 MBoe/d – 9.1 MBoe/d

Hedge Position 24 Commodity and Time Period Type Volume Price Crude Oil 2013 Collar 650 Bbls/d $90.00/Bbl - $105.80/Bbl 2013 Collar 450 Bbls/d $90.00/Bbl - $101.45/Bbl 2013 (1) Collar 1,200 Bbls/d $90.35/Bbl - $100.35/Bbl 2014 Collar 550 Bbls/d $90.00/Bbl - $105.50/Bbl 2014 Collar 650 Bbls/d $85.05/Bbl - $95.05/Bbl Crude Oil Basis Differential (Midland/Cushing) 2013 (2) Swap 2,300 Bbls/d $1.10/Bbl Natural Gas 2013 Swap 200,000 MMBtu/month $3.54/MMBtu 2013 Swap 190,000 MMBtu/month $3.80/MMBtu 2013 (3) Collar 100,000 MMBtu/month $4.00/MMBtu - $4.36/MMBtu 2014 Swap 360,000 MMBtu/month $4.18/MMBtu (1) February 2013 – December 2013 (2) March 2013 – December 2013 (3) May 2013 – December 2013 • Prudent hedging program protects cash flow and returns as well as capital budget activities 53% of FY’13 oil hedged at $90.17/Bbl x $102.19/Bbl 81% of FY’13 gas hedged at weighted average floor of $3.72/MMBtu

Liquidity 25 Liquidity (unaudited) is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. Liquidity has limitations, and can vary from year to year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. Liquidity 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 table below summarizes our liquidity at March 31, 2013, and our liquidity at March 31, 2013, on a pro forma basis to give effect to our $250 MM senior notes offering and May 1, 2013, borrowing base increase. Long-term debt-to-capital ratio (unaudited) is calculated by dividing long-term debt (GAAP) by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio 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 table below summarizes our long-term debt-to-capital ratio at December 31, 2012 and March 31, 2013, and at March 31, 2013, on a pro forma basis to give effect to our $250 MM senior notes offering in June 2013. (in thousands) March 31, 2013 Pro Forma March 31, 2013 Borrowing base $ 280,000 $ 315,000 Cash and cash equivalents 594 91,513 Long-term debt (152,250) -- Undrawn letters of credit (325) (325) Liquidity $ 128,019 $ 406,188 (in thousands) December 31, 2012 March 31, 2013 Pro Forma March 31, 2013 Long-term debt $ 106,000 $ 152,250 $ 250,000 Total stockholders’ equity 633,468 635,211 635,211 $ 739,468 $ 787,461 $ 885,211 Long-term debt-to-capital 14.3% 19.3% 28.2%

EBITDAX (unaudited) 26 (in thousands, except per-share amounts) 2Q12 3Q12 4Q12 1Q13 Net income (loss) $ 7,862 $ (2,355) $ (837) $ (347) Exploration (38) 1,170 2,131 260 Depletion, depreciation and amortization 14,596 16,728 18,027 17,056 Share-based compensation 1,311 1,450 2,472 2,257 Unrealized (gain) loss on commodity derivatives (9,439) 4,185 (1,292) 4,100 Interest expense, net 1,380 1,544 926 1,229 Income tax provision (benefit) 4,390 (1,253) (781) (187) EBITDAX $ 20,062 $ 21,469 $ 20,646 $ 24,368 EBITDAX per diluted share $ 0.60 $ 0.63 $ 0.53 $ 0.63 We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized (gain) loss on commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with 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 quarterly EBITDAX to net income (loss) for the last twelve months.

F&D Costs (unaudited) 27 We believe that providing measures of finding and development, or F&D, cost is useful to assist 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 SEC filings and posted on our website. 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 we use 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 tables reflect the reconciliation of our estimated finding and development costs to the information required by paragraphs 11 and 21 of ASC 932-235. 2012 Reserve summary (MBoe) Balance – 12/31/2011 76,975 Extensions & discoveries 38,861 Revisions (17,469) Production (2,888) Balance – 12/31/2012 95,479 Cost summary ($M) Acquisition costs $ 7,742 Exploration costs 4,550 Development costs 285,039 Total 297,331 Finding & development costs ($/Boe) All-in F&D costs $ 13.90 Drill-bit F&D cost $ 7.45 Reserve replacement ratio (%) Extensions & discoveries (MBoe) 38,861 2012 Production (MBoe) (2,888) Reserve replacement 1,346% 3-Year Reserve summary (MBoe) Balance – 12/31/2009 36,488 Extensions & discoveries 68,182 Purchases 12,456 Revisions (14,866) Production (6,781) Balance – 12/31/2012 95,479 Cost summary ($M) Acquisition costs $ 131,189 Exploration costs 17,415 Development costs 524,476 Total 673,080 Finding & development costs ($/Boe) 3-YR All-in F&D costs $ 10.23 3-YR Drill-bit F&D cost $ 7.95 Reserve replacement ratio (%) Extensions & discoveries (MBoe) 68,182 3-YR Production (MBoe) (6,781) Reserve replacement 1,005%

Contact Information MEGAN P. HAYS Manager, Investor Relations & Corporate Communications 817.989.9000 x2108 mhays@approachresources.com www.approachresources.com