Exhibit 99.2

First Quarter 2011 Investor Update FINANCIAL & OPERATING RESULTS MAY 4, 2011

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 $913 MM 5.2 MBoe/d Q1 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 $29.44 per share on 4/29/2011, plus net debt as of 3/31/2011.

1Q 2011 Highlights Production increasing Total production up 42% to 469 MBoe (5.2 MBoe/d) 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 WI in the Permian Basin now approximately 100%

1Q 2011 Financial and operating results Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 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 (MBoe/d) 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.

1Q 2011 Production and operations Production growth 42% Increase Production (MBoe/d) 41% Oil & NGLs Q1'11 production ? 42% to 5.2 MBoe/d Oil & NGL production ? 108% to 193 MBbls Drilled 17 gross (13.2 net) wells, completed 16 gross (10.7 net) wells 6 gross (6 net) wells waiting on completion Currently running 3 rigs in Project Pangea - two vertical rigs and one horizontal rig Production and operating highlights Cinco Terry M 901H 5,377-foot lateral; 15 frac stages Max rate 171 Boe/d (51 Bbls oil, 61 Bbls NGLs, 355 Mcf gas) Stabilized rate 166 Boe/d (52 Bbls oil, 58 Bbls NGLs, 337 Mcf gas) Gas volumes are post-shrink for NGL processing Horizontal Wolfcamp pilot program

2011 Capital budget $130 MM for drilling and recompletion projects in Project Pangea $76 MM for February 2011 38% WI acquisition $14 MM for lease extensions and renewals $220 MM total capital budget does not include additional lease or property acquisitions Production (MBoe/d) 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

2011 Operating and financial guidance Current 2011 Guidance Current 2011 Guidance Current 2011 Guidance Current 2011 Guidance 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/day Floor $100.00 - Ceiling $127.00 Current hedge position (1) Based on midpoint of 2011 production guidance.

Liquidity Borrowing base increase to $200 MM from $150 MM 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

Overview of AREX's Permian Assets Recent acreage acquisitions increase 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 MBoe/d Q1'11 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 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 Stratigraphic units & current AREX drilling targets

First Quarter 2011 Financial & Operating Results NON-GAAP RECONCILIATIONS

Adjusted net income reconciliation (unaudited) (in thousands, except per-share amounts) Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, 2011 2011 2010 2010 Net income $ 1,464 $ 3,563 Adjustments for certain non-cash items: Unrealized loss (gain) on commodity derivatives 149 (4,095) 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 Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 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