Approach Resources Inc. INVESTOR PRESENTATION SEPTEMBER 2013 Exhibit 99.1

Forward-Looking Statements 2 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. Cautionary Statements Regarding Oil & Gas Quantities

Company Overview • Enterprise value $1.2 BN • High quality reserve base 95.5 MMBoe proved reserves 99% Permian Basin • Permian core operating area 170,000 gross (152,000 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 25%+ production growth 3 AREX OVERVIEW ASSET OVERVIEW Notes: Proved reserves and acreage as of 12/31/2012 and 6/30/2013, 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 $24.62 per share on 9/11/2013, plus net debt as of 6/30/2013.

Key Investment Highlights • Low-Risk, Oil-Rich Asset Base • Oil and liquids-weighted asset base in Midland Basin 170,000 gross (152,000 net) primarily contiguous acres Proved reserves are 69% liquids; 2Q13 production is 70% liquids (42% 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 2Q13 lease operating expense of $4.89/Boe vs. $7.14/Boe (1Q13) and $6.03/Boe (2Q12) • Prudent Financial Management • Active hedging program • Substantial liquidity of $370 MM as of 6/30/2013 • Recent agreement to monetize pipeline further strengthens liquidity • 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 6/30/2013, respectively. See “Strong, Simple Balance Sheet” slide.

Oil Pipeline Monetization First-mover oil pipeline system in the southern Midland Basin Formed Wildcat JV to develop pipeline system in September 2012 50-miles of high-pressure, steel pipeline with throughput capacity of 100,000 Bbls/d Pipeline operational in April 2013 Announced sale of pipeline system on September 19 th AREX proceeds of $108 MM from pipeline sale Total transaction value $210 MM AREX capital contributions to pipeline system of $16.3 MM as of June 30, 2013 6.6x ROI Proceeds further strengthen liquidity position Maintain competitive oil transportation fee and firm takeaway Oil transportation differential outlook $2.50/Bbl – $4.00/Bbl 5 TRANSACTION OVERVIEW WILDCAT OIL PIPELINE SYSTEM Notes: AREX proceeds are before tax; AREX proceeds and transaction value subject to customary post-closing conditions, adjustments and escrows. Crockett Midway Truck Station Reagan Irion Schleicher

Strong Track Record of Reserve Growth… 6 RESERVE GROWTH OIL RESERVE GROWTH • YE’12 reserves up 24% YoY • 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

…and Production Growth 7 PRODUCTION GROWTH OIL PRODUCTION GROWTH • 2012 production increased 24% YoY • Targeting 25%+ 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

Oil & Liquids-Weighted Reserves, Production & Revenue 8 YE12 RESERVE MIX BY COMMODITY 2Q13 PRODUCTION MIX BY COMMODITY 2Q13 REVENUE MIX BY COMMODITY

AREX Wolfcamp Oil Shale Resource Play 9 Plan to complete ~40 to 42 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 Well costs within 5% of target HZ D&C cost of $5.5 MM per well 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 170,000 gross (152,000 net) acres Low acreage cost ~$500 per acre 940+ MMBoe gross, unrisked HZ Wolfcamp resource potential 2,096 Identified HZ Wolfcamp locations targeting the Wolfcamp A, B & C

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

Wolfcamp Stacked Pay Zones 11 Notes: Identified locations based on multi-bench development and 120-acre spacing. No locations assigned to south Project Pangea.

AREX HZ Wolfcamp Activity 12 Notes: Acreage as of 6/30/2013. Schleicher Crockett Irion Reagan Sutton Legend Vertical Producer HZ Producer HZ – Waiting on Completion HZ – Drilling HZ – Permit 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 Chandler 4403 Childress 603 Childress G 1008 Lauffer 1306 Davidson 3406 Bailey 315 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 42-23 11 42-14 10 42 A 2101H 42-15 2 42 B 1001H 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 917H 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 CT M 902 U 50 A 603HA CT L 6101H 45 C 839H 45 D 907H 45 D 905H 45 D 919H 45 D 913H 45 D 923H 45 D 927H 45D 931H 45 D 933H 45 D 903H Baker B 256H PW 6502H PW 6504H Elliott 2001HB PANGEA WEST 19,000 gross acres NORTH & CENTRAL PANGEA 92,000 gross acres SOUTH PANGEA 59,000 gross acres • 3-D seismic acquisition & data processing complete • 3-D seismic interpretation in progress • 3-D seismic interpretation complete • HZ pilot wells WOC (expect to complete during 3Q13)

Accelerating Wolfcamp Program with 3 Rigs 13 Expect to drill ~20 to 24 HZ wells per rig in 2014 vs. prior estimate of 10 to 12 HZ wells per rig 3 HZ rigs currently running in Project Pangea / Pangea West Recently drilled 2 wells in 10 to 11 days (~7,500’ lateral) Compressing spud-to-sales times Focusing activity around field infrastructure systems Field infrastructure systems beginning to contribute to lower LOE/Boe OPERATIONAL EFFICIENCY 2013 COMPLETION ACTIVITY COMPETITIVE LOE ($/Boe) Notes: Oil-weighted peer companies include CXO, EOG, FANG, KOG, LPI, OAS, PXD and ROSE. Lease operating expenses based on SEC filings for three months ended June 30, 2013. 5 7 12-14 15-17 40-42 35-40 (Prior Estimate)

HZ Wolfcamp Well Performance 14 CONTINUED STRONG WELL RESULTS & MORE PRODUCTION HISTORY – TRACKING ABOVE THE TYPE CURVE Time (Days) 0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 0 90 180 270 360 450 540 630 720

AREX HZ Wolfcamp Economics 15 Notes: Identified locations based on multi-bench development and 120-acre spacing for HZ Wolfcamp. No locations assigned to south Project Pangea. HZ Wolfcamp economics assume NYMEX – Henry Hub strip and NGL price based on 40% of WTI. Play Type Horizontal Wolfcamp Avg. EUR (gross) 450 MBoe Targeted Well Cost $5.5 MM Potential Locations 2,096 Gross Resource Potential 940+ MMBoe 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

AREX Drilling Locations, Targets & Resource Potential 16 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 17 • Reducing D&C cost to $5.5 MM and 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 50-Mile Oil Pipeline 100,000 Bbls/d Capacity

Infrastructure & Equipment Projects 18 • 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

Creating Value Through Growth • Concentrated geographic footprint in the Midland Basin • Strong growth track record at competitive costs • Detailed technical evaluation led to discovery of growth potential in the Wolfcamp oil shale resource play • Rigorous pilot program de-risked ~107,000 gross acres • 2013 Focus Reducing HZ D&C costs to $5.5 MM and lower Testing multi-bench “stacked” laterals and closer well spacing Transition to full-field development 19

Financial Information NON-GAAP RECONCILIATIONS

2Q13 Operating & Financial Highlights 21 Increasing Revenues and Lower Costs • Revenues of $42.3 MM (up 41% YoY) • Total costs and expenses of $38.35/Boe (down 9% QoQ and stable YoY) • Net income of $7.8 MM or $0.20 per diluted share • Adjusted net income (non-GAAP) of $5 MM or $0.13 per diluted share Significant Cash Flow • EBITDAX (non-GAAP) of $30.7 MM (up 53% YoY) or $0.79 per diluted share (up 32% YoY) • Cash flow from operations of $44.8 MM for the 1H’13 Strong Financial Position • Liquidity of $370 MM • Undrawn borrowing base of $315 MM • During 2Q13, issued $250 million of 7% senior notes due 2021 HIGHLIGHTS Notes: See “Adjusted Net Income,” “EBITDAX” and “Strong, Simple Balance Sheet” slides in appendix. Growing Oil Production • Total production increased to 9 Mboe/d (up 16% YoY) • Oil growing as a percentage of production (up 50% YoY) • Targeting 28 to 30 HZ well completions during 2H’13

2013 Capital Budget • 2013 Capital budget $260 MM, approx. 90% for HZ Wolfcamp • 3 HZ rigs in the Wolfcamp shale • Targeting Wolfcamp A, B and C • Testing “stacked-wellbore” development • Optimizing well spacing and completion design • Targeting 25%+ production growth • 2013 Production guidance 3.6 MMBoe – 3.9 MMBoe • 2013E Production mix 70% liquids Key takeaways: 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 Senior notes issuance, undrawn borrowing base and pipeline sale strengthen liquidity 22

Strong, Simple Balance Sheet 23 FINANCIAL RESULTS ($MM) As of 6/30/2013 Summary Balance Sheet Cash $55.3 Credit Facility – Senior Notes 250.0 Total Long-Term Debt $250.0 Shareholders’ Equity 644.3 Total Book Capitalization $894.3 Liquidity Borrowing Base $315.0 Cash and Cash Equivalents 55.3 Long-term Debt under Credit Facility – Undrawn Letters of Credit (0.3) Liquidity $370.0 Key Metrics LTM EBITDAX $97.2 Total Reserves (MMBoe) 95.5 Proved Developed Reserves (MMBoe) 32.8 % Proved Developed 34% % Liquids 69% Credit Statistics Total Debt Net Debt Debt / Capital 28% 22% Debt / 2Q13 Annualized EBITDAX 2.0x 1.6x Debt / Proved Reserves ($/Boe) $2.62 $2.04 Notes: Pipeline monetization proceeds are before taxes and subject to customary post-closing conditions, adjustments and escrows. Estimated proved reserves as of 12/31/2012. EBITDAX is a non-GAAP financial measure. See “EBITDAX” slide and website for reconciliation. Net debt is debt balance less available cash and letters of credit. Strong Balance Sheet and Liquidity to Develop HZ Wolfcamp Shale • Pipeline monetization proceeds of $108 MM further strengthen liquidity

Current 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 Feb – Dec 2013 Collar 1,200 Bbls/d $90.35/Bbl - $100.35/Bbl 2014 Collar 550 Bbls/d $90.00/Bbl - $105.50/Bbl 2014 Collar 950 Bbls/d $85.05/Bbl - $95.05/Bbl 2015 Collar 2,600 Bbls/d $84.00/Bbl - $91.00/Bbl Crude Oil Basis Differential (Midland/Cushing) Mar – Dec 2013 Swap 2,300 Bbls/d $1.10/Bbl 2014 Swap 1,500 Bbls/d $0.55/Bbl Natural Gas Liquids Propane Sept – Dec 2013 Swap 550 Bbls/d $42.00/Bbl Propane 2014 Swap 500 Bbls/d $41.16/Bbl Natural Gasoline Sept – Dec 2013 Swap 200 Bbls/d $90.72/Bbl Natural Gasoline 2014 Swap 175 Bbls/d $83.37/Bbl Natural Gas 2013 Swap 200,000 MMBtu/month $3.54/MMBtu 2013 Swap 190,000 MMBtu/month $3.80/MMBtu May – Dec 2013 Collar 100,000 MMBtu/month $4.00/MMBtu - $4.36/MMBtu 2014 Swap 360,000 MMBtu/month $4.18/MMBtu

2013 Operating and Financial Guidance 25 Full-Year 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 • 3Q13 Production guidance 8.7 MBoe/d – 9 MBoe/d • 3Q13 Exploration expense guidance $6.00/Boe – $7.00/Boe Our 2013 capital budget excludes acquisitions, lease extensions and equity contributions to our pipeline joint venture, and is subject to change depending upon a number of factors, including additional data on our Wolfcamp shale oil resource play, results of horizontal and vertical drilling, completions and recompletions, including pad drilling, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Adjusted Net Income (unaudited) 26 The amounts included in the calculation of adjusted net income and adjusted net 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 income to net (loss) income for the three months ended June 30, 2013 and 2012, respectively. (in thousands, except per-share amounts) Three Months Ended June 30, 2013 2012 Net income $ 7,787 $ 7,862 Adjustments for certain items: Unrealized gain on commodity derivatives (4,290) (9,439) Related income tax effect 1,459 3,209 Adjusted net income $ 4,956 $ 1,632 Adjusted net income per diluted share $ 0.13 $ 0.05

EBITDAX (unaudited) 27 We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized gain 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 EBITDAX to net income for the three months ended June 30, 2013 and 2012, respectively. (in thousands, except per-share amounts) Three Months Ended June 30, 2013 2012 Net income $ 7,787 $ 7,862 Exploration 557 (38) Depletion, depreciation and amortization 18,482 14,596 Share-based compensation 1,533 1,311 Unrealized gain on commodity derivatives (4,290) (9,439) Interest expense, net 2,451 1,380 Income tax provision 4,217 4,390 EBITDAX $ 30,737 $ 20,062 EBITDAX per diluted share $ 0.79 $ 0.60

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