J.P. Morgan 10 th Annual SMid Cap Conference December 1, 2011 Exhibit 99.1

| 2 | APPROACH RESOURCES Forward-looking statements Cautionary statements regarding oil and 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 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, and the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011. 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,” “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, potential drilling locations, resource potential 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 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, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, type/decline curves, per well EUR, OGIP and resource potential may change significantly as development of the Company’s oil and gas assets provides additional data. Type/decline curves, estimated EURs, typical well-related oil and gas in place, recovery factors andwell 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, 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 resource potential, 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. Unless otherwise noted, 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.

| 3 | APPROACH RESOURCES Company overview AREX overview Asset overview • Enterprise value $982 MM • High quality reserve base 66.8 MMBoe proved reserves 97% Permian Basin 55% Oil & NGLs • Permian core operating area 160,600 gross (142,000 net) acres 500+ MMBoe gross, unrisked resource potential Extensive inventory of drilling and recompletion opportunities • Strong balance sheet to execute plan Borrowing base increased 30% to $260 MM from $200 MM Pro forma liquidity of $260 MM at 9/30/2011 Notes: Proved reserves and acreage as of 6/30/2011 and 9/30/2011, 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 $29.98 per share on 11/11/2011, plus net debt as of 9/30/2011. See liquidity calculation in appendix.

| 4 | APPROACH RESOURCES Key investor highlights • Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich play 142,000+ net, primarily contiguous acres, 100% operated More than 575 wells drilled since 2004, with a 93%+ success rate • Strong growth track record at competitive costs Reserve and production CAGR since 2007 of 26% and 21%, respectively Low-cost operator with best-in-class F&D and lifting costs • Significant growth potential from Wolfcamp / Wolffork oil shale drilling inventory 2,900+ potential drilling and recompletion locations Gross, unrisked resource potential totals more than 500+ MMBoe • Meaningful upside catalysts in near future Wolffork oil shale resource play transitioning into development stage by Approach and other operators Pioneer, El Paso and EOG allocating more capital to the play Strong flow of new well result data should further derisk the play Note: See liquidity calculationin appendix.

| 5 | APPROACH RESOURCES Note: See “F&D Costs Reconciliation” slide in appendix. Strong Track Record of Reserve and Production Growth • MY’11 proved reserves up 32% to 66.8 MMBoe Oil & NGL reserves up 44% to 36.9 MMBbls • Balanced production mix in 2011 and beyond • 98% Permian Basin • Liquids content of Q3’11 production increased 148% YoY • Targeting 65% liquids-weighted production mix in 2012 • Replaced 1,598% of reserves during 1H’11 at an all-in F&D cost of $9.45/Boe • 8.4 MMBoe proved reserves booked to Wolffork oil shale resource play

| 6 | APPROACH RESOURCES Low-Cost Operator Across Crude-Oil Weighted Peers Note: Oil weighted peers include BRY, CXO, KOG, NOG, OAS, SD. Data based on SEC filings and J.S. Herold data. Lifting costs defined as lease operating expense plus taxes other than income and gathering and transportation expense. See F&D cost reconciliation page in appendix for reconciliation of 3-year F&D costs.

| 7 | APPROACH RESOURCES • 46.4 MMBoe proved reserves • 4.5 MBoe/d daily production • 98,000 net acres in Permian Basin Then… November 2010 Now… 2011 accomplishments • 66.8 MMBoe proved reserves (+44% YoY) • 6.7 MBoe/d daily production (+46% YoY) • 142,000 net acres in Permian Basin (+45% YoY) • 50% of proved reserves were liquids • 34% of production were liquids • 55% of proved reserves are liquids • 57% of production is liquids • 3 recompletions and 1 vertical well commingled in Wolffork oil shale resource play • 11 recompletions and 10 vertical wells completed through 10/30/11 • 7 horizontal Wolfcamp wells completed with 3 recent IPs ranging 798 – 1,044 Boe/d • Approach’s early view on the play has been validated by the industry • $150 MM borrowing base • $173 MM pro forma liquidity • Q3 2010 EBITDAX of $12 MM • $260 MM borrowing base • $260 MM pro forma liquidity • Q3 2011 EBITDAX of $22 MM (+83% YoY) Note: See EBITDAX reconciliation and liquidity calculation in appendix. AREX Has Delivered On Its Objectives Since Last Year

| 8 | APPROACH RESOURCES AREX Acreage Position – Favorably Located in the Permian Basin

| 9 | APPROACH RESOURCES AREX Wolffork Oil Shale Resource Play • Large, primarily contiguous acreage position 160,600 gross (142,000 net) acres (~76% NRI) Low acreage cost ~$350 per acre • Low-risk, long-life reserve base 64.8 MMBoe proved reserves 57% liquids (51% proved developed) • 3 operated drilling rigs 2 vertical rigs, 1 horizontal rig • Vertical pilot program shifting to development stage 152 BOEPD average IP for 9 recent Wolffork recompletions (75% liquids) 140 BOEPD average IP for 7 recent vertical Wolffork wells (72% liquids)

| 10 | APPROACH RESOURCES AREX Wolffork Oil Shale Resource Play – Activity Map

| 11 | APPROACH RESOURCES Wolfcamp Shale Name Convention – Southern Midland Basin Wolfcamp shale name conventions are based on investor presentations of AREX (10/18/2010), EP (5/24/2011) and PXD (9/7/2011) .

| 12 | APPROACH RESOURCES Wolffork Hydrocarbon Column – Over 2,500’ Thick

| 13 | APPROACH RESOURCES Vertical Wolffork Economics Play Type Wolffork Avg. EUR 110 MBoe Avg. Well Cost $1.2 MM F&D $10.91/Boe Potential Locations 1,825 Gross Resource Potential 200+ MMBoe VERTICAL WOLFFORK BTAX IRR SENSITIVITIES • Target Clearfork and Wolfcamp zones • Drilling depth < 7,000’ • ~75% of EUR comprised of oil and NGLs • Beginning vertical Wolffork development program • 1 active rig in NE Pangea Note: Potential locations based on 20 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price.

| 14 | APPROACH RESOURCES Vertical Wolffork Recompletion Economics Play Type Wolffork Recompletions Avg. EUR 93 MBoe Avg. Well Cost $750 M F&D $8.06/Boe Potential Locations 190 Gross Resource Potential 17+ MMBoe VERTICAL WOLFFORK RECOMPLETIONS BTAX IRR SENSITIVITIES • Target Clearfork and Wolfcamp zones • Commingle with existing production • ~75% of EUR comprised of oil and NGLs • Increasing recompletions to 4 per month beginning October 2011 Note: Potential locations based on20 to 40 acrespacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price.

| 15 | APPROACH RESOURCES Vertical Wolffork Well Profile

| 16 | APPROACH RESOURCES Vertical Canyon Wolffork Economics Play Type Canyon Wolffork Avg. EUR 193 MBoe Avg. Well Cost $1.5 MM F&D $7.77/Boe Potential Locations 440 Gross Resource Potential 85 MMBoe VERTICAL CANYON WOLFFORK BTAX IRR SENSITIVITIES • 1 active rig in Pangea Note: Potential locations based on 40 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price.

| 17 | APPROACH RESOURCES Vertical Canyon Wolffork Well Profile

| 18 | APPROACH RESOURCES Vertical Horizontal Eagle Ford 49,500 323,813 6.5x Niobrara 40,000 290,000 7.3x Wolfcamp 80,000 450,000 5.6x Well EUR (Boe) Oil Shale Play Potential Uplift Notes: Eagle Ford and Niobrara well EURs from industry publications. Wolfcamp well EUR is based on AREX estimates. Horizontal Wolfcamp – Enhancing Wolfcamp Value

| 19 | APPROACH RESOURCES Horizontal Wolfcamp Economics Play Type Horizontal Wolfcamp Avg. EUR 450 MBoe Targeted Well Cost $5.5 MM F&D $12.22/Boe Potential Locations 500 Gross Resource Potential 225 MMBoe HORIZONTAL WOLFCAMP BTAX IRR SENSITIVITIES • Horizontal drilling improves recoveries and returns • Target Wolfcamp zone • 7,000’+ lateral length, 20+ frac stages • ~74% of EUR comprised of oil and NGLs • Recent horizontal pilot results encouraging • Transitioning to development program – 1 active rig in Pangea Note: Potential locations based on 1,000-foot spacing between each horizontal well. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price.

| 20 | APPROACH RESOURCES Horizontal Wolfcamp Well Performance RECENT HORIZONTAL WOLFCAMP RESULTS University 45 C 803H – 7,358’ lateral, 23 frac stages Initial 24-hour flow rate 1,044 BOEPD, 95% liquids (931 BO, 57 Bbls NGLs, 335 MCFG) University 45 B 2401H – 7,613’ lateral, 23 frac stages Initial 24-hour flow rate 811 BOEPD, 86% liquids (582 BO, 116 Bbls NGLs, 677 MCFG) University 45 D 902H – 7,770’ lateral, 23 frac stages Initial 24-hour flow rate 798 BOEPD, 88% liquids (611 BO, 95 Bbls NGLs, 552 MCFG) UPCOMING HORIZONTAL WOLFCAMP WELLS University 42 B 1001H – 7,769’ lateral Targeting the Wolfcamp “C” zone University 45 E 1101H – 7,712’ lateral University 45 F 2301H – 7,000’+ lateral CONSISTENTLY IMPROVING WELL RESULTS

| 21 | APPROACH RESOURCES Horizontal Wolfcamp Well Profile

| 22 | APPROACH RESOURCES Summary – AREX Total Resource Potential Play Type Locations Avg. EUR (MBoe) F&D ($/Boe) Gross Resource Potential (MMBoe) Horizontal Wolfcamp 500 450 12.22 225 Vertical Wolffork 1,825 110 10.91 200 Vertical Canyon Wolffork 440 193 7.77 85 Vertical Wolffork Recompletions 190 93 8.06 17 500+ MMBoe Total Gross Resource Potential

| 23 | APPROACH RESOURCES Key Investor Highlights • Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich play 142,000+ net, primarily contiguous acres, 100% operated More than 575 wells drilled since 2004, with a 93%+ success rate • Strong growth track record at competitive costs Reserve and production CAGR since 2007 of 26% and 21%, respectively Low-cost operator with best-in-class F&D and lifting costs • Significant growth potential from Wolfcamp / Wolffork oil shale drilling inventory 2,900+ potential drilling and recompletion locations Gross, unrisked resource potential totals more than 500+ MMBoe • Meaningful upside catalysts in near future Wolffork oil shale resource play transitioning into development stage by Approach and other operators Pioneer, El Paso and EOG allocating more capital to the play Strong flow of new well result data should further derisk the play • Strong balance sheet to execute development plan $260 MM borrowing base $260 MM pro forma liquidity at 9/30/2011 Note: See liquidity calculation in appendix.

APPROACH RESOURCES Financial Framework

| 25 | APPROACH RESOURCES 3Q 2011 Operating Highlights Notes: Realized price includes commodity derivatives. • Production in Project Pangea running as planned Oil inventory build of ~29 MBbls through 3Q 2011 Inventory build reduced potential sales volumes by ~315 Bbls/d during 3Q 2011 • Drilled 20 wells, completed 14 wells and recompleted 4 wells during 3Q 2011 • Horizontal Wolfcamp and vertical Wolffork wells results continue to improve Horizontal Wolfcamp wells IP at 1,044 BOEPD – 798 BOEPD Vertical Wolffork recompletions average IP at 152 BOEPD Vertical Wolffork wells average IP at 140 BOEPD

| 26 | APPROACH RESOURCES 3Q 2011 Financial Highlights Notes: See “Adjusted Net Income” and “EBITDAX” reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively.

| 27 | APPROACH RESOURCES 2011 Capital Budget 2011 PROGRAM 2 Vertical rigs Expect to drill 58 vertical wells targeting the Wolffork or Canyon Sands (13 ahead of schedule) 1 Horizontal rig Expect to drill 13 horizontal Wolfcamp wells (2 ahead of schedule) 2 to 4 recompletions per month targeting the Wolffork oil shale Leasing activity and working interest acquisition expanded footprint in Wolffork oil shale play to 142,000 net acres, up from 101,000 net acres at YE 2010 Infrastructure projects will accommodate production in northeast Project Pangea and Block 45 Notes: Our 2011 capital budget is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and natural gas, the availability sufficient capital resources for drilling prospects, our financial results, the availability of drilling and completion occ

| 28 | APPROACH RESOURCES 2012 Capital Budget 2012 PROGRAM 2012 Capital budget $160 MM 2 Vertical rigs, 1 horizontal rig and 2 to 4 recompletions per month targeting the Wolffork oil shale Substantially same rig program as 2011 Targeting 20%+ production growth 2012 production guidance 2,800 MBoe – 3,000 MBoe Key takeaways: Notes: Our 2012 capital budget is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and natural gas, the availability sufficient capital resources for drilling prospects, our financial results, the availability of drilling and completion services and materials on reasonable terms, and lease extensions and renewals. Additionally, we may increase our 2012 capital budget if we acquire acreage or accelerate our drilling program. Initial 2012 capital program provides flexibility to develop Wolffork oil shale and monitor commodity prices and service costs Increase in liquids production drives expected increase in cash flow Increase in borrowing base strengthens liquidity

| 29 | APPROACH RESOURCES 2011 & 2012 Operating and Financial Guidance Guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control. See slide 2, “Forward-looking statements,” for additional information.

| 30 | APPROACH RESOURCES • 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 – 2012 Collars contracted for 1,200 Bbls/d at weighted average floor $87.08 – ceiling $101.08 (1) Based on midpoint of 2011 production guidance. Hedge Position CURRENT HEDGE POSITION

APPROACH RESOURCES Appendix NON-GAAP RECONCILIATIONS

APPROACH RESOURCES | 32 | APPROACH RESOURCES Liquidity 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. However, this measurement has limitations. This measurement 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. This measurement 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 September 30, 2011, and our liquidity position at September 30, 2011, reflecting the October 2011 borrowing base increase to $260 million from $200 million, and our liquidity at September 30, 2011, as further adjusted for our November 2011 follow-on equity offering of 4,600,000 shares. Liquidity (unaudited) Note: Liquidity as further adjusted is based on issuance of 4,600,000 shares at $28.00 per share.

| 33 | APPROACH RESOURCES 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. F&D costs reconciliation (unaudited) Note: F&D costs exclude asset retirement obligations of $6.3 million at 6/30/2011 and $5.4 million at 12/31/2010.

| 34 | APPROACH RESOURCES 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. Adjusted Net Income Reconciliation (Unaudited)

| 35 | APPROACH RESOURCES 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) 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. EBITDAX Reconciliation (Unaudited)