Approach Resources (AREXQ) 8-K Regulation FD Disclosure

Exhibit 99.1

www.approachresources.com | 6500 W. Freeway, Suite 800 Fort Worth, Texas 76116 | 817.989.9000 Houston, Texas May 20, 2008

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 plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company's drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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. These include risks and uncertainties relating to financial performance and results, prices and demand for oil and natural gas, availability of drilling and production equipment and personnel, availability of sufficient capital to execute our business plan, risks associated with drilling and operating wells, our ability to replace reserves and efficiently develop and exploit our current reserves and other important factors that could cause actual results to differ materially from those projected in the forward-looking statements. When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements found in the Company's Annual Report on Form 10-K and Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission (SEC) on March 28, 2008 and May 8, 2008, respectively. Information in this presentation, including 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 such information or statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms "estimated ultimate recovery," "EUR," "probable," "possible" and "non-proven" reserves, reserve "potential" or "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company.

About Approach Founded 2002 IPO November 14, 2007 Exchange/Ticker Nasdaq / AREX Market cap $475 mm(1) Shares outstanding 20.7 mm (1)Based on 5/12/2008 closing price and 20.7 mm shares outstanding.

Management and company history Approach management/technical team has an average of 28 years of industry experience Track record of creating value for investors 1988: American Cometra (shallow & deep tight gas sands) Ross Craft joined American Cometra in 1988 American Cometra sold assets in two separate transactions in 1995 and 1997 to Range and Pioneer, respectively 1998: Athanor Resources (tight gas - U.S. & Tunisia) Funded by Yorktown Partners Sold U.S. assets in 2002 to Nuevo Energy 2002: Approach Resources founded Funded by Yorktown Partners Drilled first well in Ozona Northeast in 2004

Areas of operation

Key investment highlights Total: 859 locations Cinco Terry 119 East Texas 61 Ozona Northeast 679 Southwest Kentucky 27% Cinco Terry 8% East Texas 2% British Columbia 5% Ozona Northeast 9% Northern New Mexico 49% Total: 164,140 net acres Identified development drilling lcoations(1) High quality, long-lived asset base Low risk, repeatable, multi-year drilling inventory Sizeable acreage position in prospective unconventional resource plays Financial flexibility Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Emerging plays British Columbia Montney tight gas / Doig shale Southwest Kentucky New Albany Shale, thermogenic gas Northern New Mexico Mancos Shale (oil) (1)As of 12/31/07 reserve report. Net undeveloped acreage

Stock performance(1) Small cap peer group (<$2B) % return since YE07 AREX: 73% return since YE07 Peer average: 42% return since YE07 (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 5/9/2008. - -30% - -20% - -10% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 120% 130% 140% 150% AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

Value proposition(1) Small cap peer group (<$2B) EV/Mcfe ($) AREX: $2.63 EV/Mcfe proved reserves Peer average: $4.71 EV/Mcfe proved reserves (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 5/9/2008. 0 1 2 3 4 5 6 7 8 9 10 11 AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

Production and reserve growth Production growth (MMcfe/d) Proved reserves growth (Bcfe) (1) (3) (1)Pro forma for the acquisition of Neo Canyon Exploration, L.P.'s 30% working interest in Ozona Northeast, as if the acquisition occurred on January 1, 2007. (2)Based on mid-point of production guidance of 8.5 Bcfe - 9.0 Bcfe released May 6, 2008. (3)Pro forma for the acquisition of the Neo Canyon interest, as if the acquisition occurred on January 1, 2006. (2) Historic growth is organically driven Ozona Northeast historically represented majority of production and reserves Other development plays now contributing (Cinco Terry and North Bald Prairie) Currently four rigs running Observations 60 109 149 180 2004 2005 PF 2006 2007 4 14 18 19 24 2004 2005 2006 PF 2007 2008 (Projected)

12/31/2007 Reserve summary and unrisked potential Reserve overview(1) Total reserves by category Reserve mix Oil 11% Gas 89% PUD 27% PD 20% Resource 18% Possible 11% Probable 23% Unbooked reserve potential: 205.5 Bcfe (1)Estimates of proved, probable and possible reserves, PV-10 and capex are based on independent engineering study of Approach's oil and gas properties prepared by DeGolyer and MacNaughton. Resource reserve estimates are based on internal company studies. Probable, possible and resource reserves are unrisked and unbooked. (2)PV-10 reconciliation provided on page 31.

Operating as a low-cost producer: Projected 2008 operating expenses comparison(1) Small cap peer group (<$2B) LOE & severance tax ($/Mcfe) AREX: $1.11 LOE & severance tax ($/Mcfe) Peer average: $1.98 LOE & severance tax ($/Mcfe) (1)Source: JPMorgan Oil & Gas Exploration and Production Weekly E&P Comp Table, 5/16/2008. $0.00 $1.00 $2.00 $3.00 $4.00 AREX BEXP CRZO CXO DPTR EPEX EAC END XCO GSX GDP ME MMR PVA PQ SGY SFY VQ WLL

2008 Capital budget Key projects and objectives for 2008 Capital budget and key projects 2 rigs running in Ozona Northeast Continue development drilling in Cinco Terry 22 wells drilled and completed through April 2008 Benefit from high crude oil prices High Btu content of gas with substantial NGL recoveries Test horizontal Wolfcamp Develop North Bald Prairie prospect in East Texas 5 wells drilled since August 2007 6th well spudded April 2008 Develop British Columbia Montney tight gas sands and Doig shale project Test and evaluate prospectivity of New Albany shales in Southwest Kentucky Total: $80.0 mm - - G&G, other Southwest Kentucky - Cinco Terry - East Texas - British Columbia - - Ozona Northeast 47% 25% 18% 2% 4% 4%

Ozona Northeast field Canyon Sands tight gas development Legacy asset with significant remaining development potential 140.7 Bcfe estimated proved reserves YE07, 100% operated Low decline rates (4%-6%) in mature wells 41,716 net acres (14,816 undeveloped) Own and operate 65 miles of gathering lines 679 identified drilling locations YE07 Drilling inventory map(1) Key highlights 2008 plans Keep 2 rigs operating full time through 12/2008 Accelerate drilling in high natural gas price environment Reprocess 3-D seismic 2008 capital budget - $37.5mm (1)As of December 31, 2007 reserve report.

Ozona Northeast: Reprocessing 3-D seismic Identify sand channels with more precision than before Target multiple depths not previously identified Drill fewer wells with higher EURs per well 3-D seismic image Interpretation Hemphill 1202 - drilled & abandoned Sand channel - drill one well here and target three separate depths 1,800 ft.

Ozona Northeast typical Canyon well Statistical, predictable results 513 - 482 MMcfe average gross EUR 391 - 367 MMcfe average net EUR (80% NRI) Premium price realization driven by high gas heat content 1,260 Btu per Mcfe Make-whole contract (wellhead) Realize slight premium to Henry Hub NYMEX (on per Mcfe basis) D&C costs $760k per well Estimated rate of return - based on 482 MMcfe 65% at $8.14 Henry Hub $1.1 mm NPV per well at 10% discount rate Expected breakeven at $3.25 Henry Hub Key observations Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas and $90.20/Bbl WTI Oil ($'000s) Drill & Complete ($1,000) ($500) $0 $500 $1,000 $1,500 $2,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs.

Cinco Terry project Canyon Sands tight gas development Ellenburger development 18.3 Bcfe estimated proved reserves YE07 31,380 gross (14,406 net) acres (13,259 net undeveloped) 119 identified Canyon drilling locations YE07 Drilled and completed 22 wells through April 2008 (9 Canyon/13 Ellenburger) EURs 514 MMcfe - 2 Bcfe (gross) D&C costs $700k to $850k Estimated IRRs ^ 50% Drilling inventory map(1) Key highlights 2008 plans 2 rigs operating full-time through 12/2008 Drill horizontal test well into Wolfcamp Recently acquired 9,482 gross (4,899 net) acres 2008 capital budget - $20.2mm Drill 42 Canyon/Ellenburger/Wolfcamp wells Multiple horizon potential Depth in feet 3,000 - 4,500 7,500 - 8,100 8,200 - 8,800 Wolfcamp/Sprayberry Canyon Sands Ellenburger (1)As of 5/16/2008.

Cinco Terry: Proposed 3-D seismic 3-D seismic area

Cinco Terry Ellenburger average daily production & initial potential rates(1) (1)Gross average daily and initial potential rates through May 13, 2008. (2)Restimulating. Mcfe/d Well # Initial potential Average daily production Summary Drilled and completed 15 Ellenburger wells through May 16, 2008 1.2 MMcfe/d average initial production 820 Mcfe/d average daily production 1,296 MMcfe average gross EUR 571 MMcfe average net EUR (2) 0 500 1000 1500 2000 2500 803 805 807 902 903 905 907 2001 2302 141 151 221 222 223 231

Cinco Terry typical Canyon well Statistical, predictable results +-50% WI & +-39% NRI 514 MMcfe average gross EUR 208 MMcfe average net EUR 88% POP increasing to 90% after 1.4 Bcfe transported through system 1,220 current Btu gas Fixed recoveries, fuel and shrink D&C costs (gross) $850k per well Estimated rate of return - 60% $577k NPV per well at 10% discount rate Key observations ($'000s) Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas, $90.20/Bbl WTI Oil, $54.12/Bbl NGL Drill & Complete ($1,000) $0 $1,000 $2,000 $3,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs.

Cinco Terry typical Ellenburger well Statistical, predictable results +-50% WI & +-39% NRI 1,197 MMcfe average gross EUR 571 MMcfe average net EUR 88% POP increasing to 90% after 1.4 Bcf transported through system 1,220 current Btu gas Fixed recoveries, fuel and shrink D&C costs (gross) $775k per well Estimated rate of return - 275% $2.3 mm NPV per well at 10% discount rate Key observations ($'000s) Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas, $90.20/Bbl WTI Oil, $54.12/Bbl NGL Drill & Complete ($1,000) $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs ..

North Bald Prairie prospect - East Texas Cotton Valley Lime, Bossier, Cotton Valley Sands development 21.4 Bcfe estimated proved reserves YE07 10,300 gross (4,900 net) acres (50% WI & +-40% NRI) 61 locations identified YE07 Average EURs of 1.5 Bcfe (gross) Expected D&C cost per well $1.9mm (gross) Estimated average IRRs ^ 40% Rodessa and Pettit upside D&C'd 5 producing wells since August 2007 Currently drilling next 5 locations Acreage map(1) Key highlights 2008 plans 1 rig operating full time 2008 capital budget - $14.4mm Drill 11 CVL/Bossier/CVS wells (1)As of May 16, 2008.

North Bald Prairie typical CVL, Bossier, CVS well Statistical, predictable results 50% WI & 40% NRI 1,504 MMcfe average gross EUR 592 MMcfe average net EUR D&C costs (gross) $2 mm per well at 12/31/2007 Estimated rate of return - 49% $991k NPV per well at 10% discount rate Key observations ($'000s) Cumulative well cash flow profile at $8.14/Mcf Henry Hub Gas Drill & Complete ($2,000) ($1,000) $0 $1,000 $2,000 $3,000 $4,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Yrs ..

British Columbia 25% non-operated working interest 28,860 gross (6,865 net) acres Primary targets are Montney tight gas sands and Doig shale 2008 capital budget - $3.0 mm Exploratory plays Western Kentucky - Boomerang New Albany Shale 74,000 gross (44,000 net) undeveloped acres Long dated leases (5 year prime + 5 year extension) provide long term option value on technology and gas prices After evaluating results from 2008 test wells, determine development program for the prospect 2008 capital budget - $1.8 mm Northern New Mexico - El Vado East Mancos Shale low cost exploration 2,000 to 3,000 feet 90,300 gross (81,000 net) undeveloped acres Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations April 2008 - Board of County Commissioners of Rio Arriba County adopts 120-day oil & gas drilling moratorium covering Approach's acreage Currently, deferring 2008 capital expenditures

Financial strategy Maintain conservative financial policy $7.3 mm outstanding under our credit facility at 3/31/2008 Prudent use of leverage going forward Maintain ongoing financial flexibility to pursue acquisitions or accelerate development $100 mm borrowing base Operate our properties as a low cost producer Fund development drilling budget substantially from operating cash flow Employ commodity price hedging program Secure cash flow to fund development drilling program Use combination of swaps and collars Hedge basis differential

Financial and operating guidance 2008 financial and operating guidance The 2008 financial and operating guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control, as described on page 2 of this presentation and in our SEC filings.

Ownership of management and certain beneficial owners Equity ownership Number of Shares of Common Stock Owned (mm) Percent Management and Affiliates Yorktown Energy Partners 9.4 46 % Lubar Equity Fund, LLC 0.9 4 % Officers, directors and employees 1. 1 5 % Subtotal 11.4 55 % Certain Beneficial Owners 0.2 1 % Public Stockholders 9.1 44 % Total 20. 7 100 %

Appendix A

Condensed balance sheet $ thousands

Financial and operating data $ thousands, except per unit metrics (1)EBITDAX reconciliation provided on page 30. Three Months Ended Three Months Ended March 31, March 31, 2008 2007 Revenues (in thousands) : Gas ................................. .................... $ 14,872 $ 8,255 Oil ................................. ..................... 3,085 1,090 NGLs ................................. .................. 1,061 47 Total oil and gas sales .......................... 19,018 9,392 Realize d gain on commodity derivatives ................................. ........ 61 2,155 Total oil and gas sales including derivative impact ........................... $ 19,079 $ 11,547 Production : Gas (MMcf) ................................. .......... 1,666 1,231 Oil (MBbl) ................................. ........... 32 19 NGLs ................................. ................. 21 2 Total (MMcfe) ................................. ... 1,979 1,357 Average prices : Gas, per Mcf ................................. ....... $ 8.93 $ 6.70 Oil, per Bbl ................................. ......... 97.91 56.22 NGLs ................................. ................ 50.95 30.12 Total, per Mcfe ................................. .. 9.61 6.92 Realized gain on commodity derivatives, per Mcfe ........................... 0.03 1.59 Total per Mcfe including derivative impact ................................. ....... 9.6 4 8.51 Costs and expenses ( per Mcfe ): Lease operating expenses ........................ $ 0.71 $ 0.72 Severance and production taxes ................. $ 0.38 $ 0.28 Depletion, depreciation and amortization ................................. ..... $ 2.64 $ 2.28 Exploration ................................. .......... $ 0.25 $ 0.46 General and administr ative ...................... $ 0.98 $ 1.11 EBITDAX ( 1 ) (in thousands) ......................... $ 15,20 9 $ 8, 6 80

EBITDAX(1) reconciliation (unaudited) $ thousands (1)EBITDAX is presented in this presentation and reconciled to the generally accepted accounting principle ("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. We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized 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.

PV-10(1) reconciliation (unaudited) $ thousands (1)The table above shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future cash flows from estimated proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their present value. We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating gas and oil companies. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

Current natural gas hedges Hedging positions