Exhibit 99.1

MAY 19, 2011 Canaccord Genuity Permian Basin Field Trip J. Ross Craft, President & CEO

#####

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 Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, 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 Annual Report on Form 10-K for the year ended December 31, 2010. 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 "potential," "upside," "oil and gas in place" or "OGIP," "OIP" or "GIP," 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, drilling locations and OGIP estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company's interest will differ substantially. 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, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, per well EUR, OGIP and upside potential may change significantly as development of the Company's oil and gas assets provides additional data. Type/decline curves, estimated EURs, related oil and gas in place, recovery factors and well costs represent Company-generated 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, OGIP, 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 EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates 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 and gas quantities

#####

Approach Resources Inc. AREX overview Enterprise value $758 MM 5.2 MBOEPD 1Q 2011 production 41% Oil & NGLs 59% Natural gas 59.7 MMBoe proved reserves 96% Permian Basin 52% Oil & NGLs 52% Proved developed No proved reserves currently booked for Wolffork development 153,700 gross (134,500 net) acres in the Permian Basin 2,780+ potential drilling and recompletion opportunities in the Permian Basin Permian-focused operations Notes: Proved reserves and acreage as of 3/31/2011, and include 38% working interest acquisition in February 2011. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing price of $24.00 per share on 5/11/2011, plus net debt as of 3/31/2011.

#####

Key investor highlights Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich plays 134,500+ net, primarily contiguous acres, 100% operated More than 525 wells drilled by Approach since 2004, with a 93%+ success rate Established basin infrastructure Strong growth track record at competitive costs Reserve and production CAGR since 2004 of 31% and 46%, respectively Low-cost operator with best-in-class F&D and lifting costs Significant growth potential from drilling inventory supported by extensive technical evaluation 1,070 potential Canyon Wolffork new drills 1,230 potential horizontal Wolfcamp locations 480 potential behind pipe Wolffork recompletion opportunities Strong balance sheet to execute development plan $74.2MM of liquidity at 3/31/2011 Borrowing base increased to $200MM ($124.2MM of liquidity at 3/31/2011, including borrowing base increase) Significant potential upside from future development of drilling inventory Note: Liquidity calculation provided in appendix.

#####

Recent operating and financial highlights Production increasing Total production up 42% to 469 MBOE (5.2 MBOEPD) over 1Q 2010 Total production up 8% over 4Q 2010 Oil & NGL production increased 108% to 193 MBbls Total production mix 41% oil & NGLs, 59% natural gas Strong revenues, EBITDAX Revenues up 53% to $20.2 million over 1Q 2010 EBITDAX up 55% to $14 million over 1Q 2010 Expanded core acreage position in the Permian Basin During 1Q 2011, AREX acquired approximately 17,600 net acres in the Permian Basin As of March 31, 2011, Permian acreage position covers 134,500 net acres, 100% operated Increased working interest in the Permian Basin In February 2011, acquired remaining 38% working interest in Cinco Terry Working interest in the Permian Basin now approximately 100% 1Q 2011 Highlights 1Q 2011 Production growth (CHART) 42% Increase Production (MBOEPD) 41% Oil & NGLs Notes: See "EBITDAX" reconciliation slide in appendix for reconciliation of EBITDAX.

#####

(CHART) 52% Oil & NGLs 2004-2010 CAGR: 31% (CHART) 2004-2011E CAGR: 46% Proved reserves (MMBoe) Production (MBOEPD) 55% Oil & NGLs Note: 3/2011 Proved reserves include 38% working interest acquisition in February 2011. 2011E production and production mix based on the midpoint of production guidance. Strong track record of reserve and production growth Production growth Reserve growth

#####

(CHART) (CHART) Notes: Peers include BRY, BEXP, CXO, KOG, NOG, OAS, PETD, and SD. Based on public filings. Lifting costs defined as lease operating expense plus taxes other than income and gathering and transportation expense. See "F&D costs reconciliation" slide in appendix for reconciliation of 3-year average F&D costs for AREX. $7.99 $8.95 Low-cost operator across crude-oil weighted peers 1Q 2011 lifting costs ($/Boe) 3-Year average F&D costs ($/Boe)

#####

2011 Capital budget (CHART) $130 MM for drilling and recompletion projects in Project Pangea $76 MM for February 2011 38% WI acquisition $14 MM for seismic acquisition and lease acquisitions, extensions and renewals $220 MM total capital budget does not include additional lease or property acquisitions (CHART) (CHART) Production (MBOEPD) 2010 2011E 69% Gas 31% Oil & NGLs 45% Gas 55% Oil & NGLs 2011 Plan Note: Production growth and production mix based on midpoint of 2011 production guidance. Targeting 50%+ production growth Oil & NGL expected production growth in '11 4.3 MBOEPD 6.5 MBOEPD

#####

Midland Basin Delaware Basin Central Basin Platform Northwest Shelf Eastern Shelf Wolffork Play 250 miles by 300 miles 1st commercial oil accumulation (Westbrook) discovered in 1921 Over 30 billion barrels of oil produced over last 90 years Largest oil and gas producing area in Lower 48 Over 1,300 oil reservoirs and 30 plays identified Approximately 80% of producing reservoirs <10,000' Over 400 US rigs are active in Permian Source: USGS, Bureau of Economic Geology, Baker Hughes and IHS. Permian Basin - World class petroleum basin Permian Basin

#####

AREX acreage is favorably located in the Permian Basin

#####

Recent leasing activity in the Wolffork play Large independents and a major enter the Southern Midland Basin through UT's Lease Sale

#####

Overview of AREX's Permian Basin assets Recent acreage acquisitions increase Southern Midland Basin acreage position to 153,700 gross (134,500 net) acres Project Pangea AREX operated with average ~100% WI, ~76% NRI 57.3 MMBoe proved reserves 5.2 MBOEPD 1Q'11 production 2,780+ potential drilling and recompletion locations targeting Wolffork, Canyon Sands and deeper zones Significant upside potential in Wolffork play Emerging oil shale resource play located above traditional Canyon, Strawn and Ellenburger targets 1,070 potential Canyon Wolffork new drills 1,230 potential horizontal Wolfcamp locations 480 potential Wolffork recompletions Recent horizontal Wolfcamp wells results demonstrate AREX's progress in the play Cinco Terry M 901H - 5,377-foot lateral, 15 frac stages Initial 24-hour flow rate 171 BOEPD , 65% liquids (51 Bbls oil, 61 Bbls NGLs, 355 Mcf gas) University 42 21 1H - 7,037-foot lateral, 21 frac stages Initial 24-hour flow rate 316 BOEPD, 71% liquids (132 Bbls oil, 93 Bbls NGLs, 543 Mcf gas) Dean Clearfork /Spraberry Wolfcamp Cisco Canyon Ellenburger Strawn San Andres Grayburg 2,500' gross pay Southern Midland Basin Val Verde Basin Ozona Arch Tight sand Target Carbonate Carbonate Shale Shale Wolffork Shale Project Pangea & Pangea West Note: Gas volumes for horizontal Wolfcamp well results are post-shrink for NGL processing. Current AREX drilling targets

#####

Wolfcamp rock characteristics TOC for Wolfcamp Shale from whole core of Baker A112: Thermal Maturity OIL ..6 ..9 1.20 1.35 2.0 3.0 Peak Wet Gas Dry Gas Peak Oil Floor Wet Gas Floor Dry Gas Floor R0 Baker A112 Wolfcamp R0 ~0.95-0.97 Richness Good - Excellent Fair TOC (%) 2-10 1-2 <1 Poor 2.24% - 7.24% Natural Fractures Organic material Quartz and carbonate materials Core porosity % Core porosity for Baker A112 Fractures Absorption Oil & gas storage criteria for shales: Matrix pore space Fractures Adsorption Wolfcamp shale: World class source rock in oil window Significant oil & gas storage space

#####

University 40-13 1H Baker A 112 Bailey 310 ~12.5 miles ~12.8 miles SW Irion Co Cinco Terry Ozona NE Dean 6,100 6,200 6,300 6,400 6,500 6,600 6,700 6,800 6,900 7,000 7,100 5,500 5,600 5,700 5,800 5,900 6,000 6,100 6,200 6,300 6,400 6,500 4,900 5,000 ,5,100 5,200 5,300 5,400 5,500 5,600 5,700 5,800 5,900 Wolfcamp A Wolfcamp B Wolfcamp C 0 200 GR API 0.3 -0.1 NPHI 0.3 -0.1 DPHI 0 200 GR API 0.3 -0.1 NPHI 0.3 -0.1 DPHI 0 200 GR API 0.3 -0.1 NPHI 0.3 -0.1 DPHI Wolfcamp regional correlation

#####

Over 2,500 feet of gross pay in the Wolffork AREX Baker A112 Clearfork A Clearfork B Clearfork C Hydrocarbon bearing zone

#####

Note: Wolffork economics based on NYMEX strip in October 2010, estimated F&D cost calculated as D&C cost divided by total well EUR. Wolffork economics summary (estimated) AREX technical evaluation yields Original Oil & Gas in Place resource per section of 118 MMboe for Wolfcamp shale and 63 MMboe for Dean/Clearfork EUR estimates support conservative recovery assumptions of 10% for gas and 3% for oil Optimized drilling and completion efforts could improve recovery factors, increasing EUR per well Type/decline curves, estimated EURs, related oil and gas in place, recovery factors and well costs represent Company-generated 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, OGIP, 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 EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates 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. Oil (Bbl) NGL (Bbl) Gas (Mcf) Total (BOE) Wolfcamp Recompletion 21,910 16,592 100,680 55,282 550,000 19% 9.95 Wolffork Recompletion 40,950 24,800 145,702 90,034 850,000 25% 9.44 480 Canyon Wolffork New Drill 75,420 63,170 390,648 203,698 1,700,000 32% 8.35 1,070 Wolfcamp Horizontal (Development Well) 191,032 79,512 498,336 353,600 3,500,000 30% 9.90 1,230 Potential Drilling Locations F&D Cost per BOE ($) IRR Type Well EUR D&C Cost ($)

#####

Oil shale play comparison *Density porosity ranges from 8% to 15%. Notes: The shale rock property (SRP) data for Bakken, Barnett, Eagle Ford and Niobrara are from industry publications. The SRP data for Wolffork are based on AREX Baker A 112 whole core. How does the Wolffork play stack up against other commercial oil shale plays?

#####

Appendix Non-gaap reconciliations & other financial information

#####

1Q 2011 Financial and operating results Three Months EndedMarch 31, Three Months EndedMarch 31, Three Months EndedMarch 31, Three Months EndedMarch 31, 2011 2011 2010 2010 Revenues ($M) $ 20,183 $ 13,220 Net income ($M) $ 1,464 $ 3,563 Net income per diluted share $ 0.05 $ 0.17 Adjusted net income (non-GAAP) ($M) $ 1,244 $ 200 Adjusted net income per diluted share $ 0.04 $ 0.01 EBITDAX (non-GAAP) ($M) $ 13,965 $ 8,987 EBITDAX per diluted share $ 0.49 $ 0.43 Realized price ($/Boe) (excluding commodity derivatives) $ 43.03 $ 40.02 Production (MBOEPD) 5.2 3.7 Net income and adjusted net income (non-GAAP) were impacted by $4.6 million of exploration expense, of which $3.2 million was related to lease extensions in our core operating area in the Permian Basin that we elected to pay in 1Q 2011 ahead of the University Lease Sale on March 31, 2011. The after-tax impact of the $3.2 million in exploration expense was $2.1 million, or $0.07 per diluted share Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively.

#####

2011 Operating and financial guidance Current 2011Guidance Current 2011Guidance Current 2011Guidance Current 2011Guidance Production Total (MBoe) 2,300 - 2,450 2,300 - 2,450 2,300 - 2,450 Percent Oil & NGLs 55% 55% 55% Operating costs and expenses ($/per Boe) Lease operating $ 4.25 - 5.50 4.25 - 5.50 4.25 - 5.50 Severance and production taxes $ 2.00 - 2.30 2.00 - 2.30 2.00 - 2.30 Exploration $ 4.00 - 5.00 4.00 - 5.00 4.00 - 5.00 General and administrative $ 5.00 - 6.00 5.00 - 6.00 5.00 - 6.00 Depletion, depreciation and amortization $ 12.00 - 15.00 12.00 - 15.00 12.00 - 15.00 Capital expenditures ($MM) Approximately $220 Approximately $220 Approximately $220

#####

2011 Hedge position Natural gas (NYMEX - Henry Hub) 2011 Price swaps contracted for 230,000 MMBtu/month at $4.86/MMBtu June 2011 - December 2011 Price swaps contracted for 200,000 MMBtu/month at $4.74/MMBtu 65% of estimated 2011 natural gas production hedged at weighed average price of $4.82/MMBtu(1) Natural gas (WAHA - Basis Differential) 2011 Basis swaps contracted for 300,000 MMBtu/month at $(0.53)/MMBtu Oil (NYMEX - West Texas Intermediate) May 2011 - December 2011 Collars contracted for 1,000 Bbls/d Floor $100.00 - Ceiling $127.00 Current hedge position (1) Based on midpoint of 2011 production guidance.

#####

Liquidity Borrowing base increase to $200MM from $150MM Current liquidity position (unaudited) (in thousands) Liquidity at March 31, 2011 Liquidity at March 31, 2011 Liquidity with Borrowing Base Increase at March 31, 2011 Liquidity with Borrowing Base Increase at March 31, 2011 Borrowing base $ 150,000 $ 200,000 Cash and cash equivalents 1,255 1,255 Outstanding letters of credit (350) (350) Long-term debt (76,700) (76,700) Liquidity $ 74,205 $ 124,205

#####

Adjusted net income reconciliation (unaudited) (in thousands, except per-share amounts) Three Months EndedMarch 31, Three Months EndedMarch 31, Three Months EndedMarch 31, Three Months EndedMarch 31, 2011 2011 2010 2010 Net income $ 1,464 $ 3,563 Adjustments for certain non-cash items: Unrealized loss (gain) on commodity derivatives 149 (5,095) Gain on sale of oil and gas properties (488) ^ Related income tax effect 119 1,732 Adjusted net income $ 1,244 $ 200 Adjusted net income per diluted share $ 0.04 $ 0.01 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.

#####

EBITDAX reconciliation (unaudited) We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) gain on sale of oil and gas properties, (6) interest expense, and (7) 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. (in thousands, except per-share amounts) Three Months EndedMarch 31, Three Months EndedMarch 31, Three Months EndedMarch 31, Three Months EndedMarch 31, 2011 2011 2010 2010 Net income $ 1,464 $ 3,563 Exploration 4,628 1,490 Depletion, depreciation and amortization 6,052 5,835 Share-based compensation 835 580 Unrealized loss (gain) on commodity derivatives 149 (5,095) Gain on sale of oil and gas properties (488) ^ Interest expense, net 513 466 Income tax provision 812 2,148 EBITDAX $ 13,965 $ 8,987 EBITDAX per diluted share $ 0.49 $ 0.43

#####

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 included in our Annual Report on Form 10-K filed with the SEC on March 11, 2011. 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 table reflects the reconciliation of our estimated finding and development costs to the information required by paragraphs 11 and 21 of ASC 932-235: Slide 25 F&D costs reconciliation (unaudited)