Exhibit 99.1

Company Presentation June 24, 2010

June 24, 2010 Slide 2 Forward-looking statements and cautionary 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 drilling program, estimated reserves and drilling locations, hedging activities, capital expenditures, financial and operating guidance, 3-D seismic data interpretation and potential value added by processing NGLs included in the 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 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" 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 filed with the Securities and Exchange Commission ("SEC") on March 12, 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 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," "EUR," reserve "potential," "upside" or 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. Reconciliations and definitions for non-GAAP financial measures and other measures used throughout this presentation are included in the appendix to this presentation. Information regarding non-GAAP financial measures and other measures also is posted on the Non-GAAP Financials page of the Company's website at www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Company overview Equity ownership at 6/2010 (in millions) (in thousands, unless otherwise noted) June 24, 2010 Slide 3 AREX share price (6/21/2010) 7.89 $ Shares outstanding (3/31/2010) 21,003 Market cap 165,714 Net debt (3/31/2010) 36,574 $ Enterprise value (EV) 202,288 $ YE09 Proved reserves (MMcfe) 218,928 EV per proved Mcfe 0.92 $ Management and Affiliates Yorktown Energy Partners ................................ ........................ 3.8 18 % Lubar Equity Fund, LLC ................................ ............................. 0.9 4 % Officers, directors and employees ................................ ............ 1.7 8 % Subtotal ................................ ................................ ................ 6.4 30 % Public Float 5% Beneficial owners (at 3/31/2010) ................................ ....... 2.4 12 % Other stockholders ................................ ................................ ... 12 . 2 58 % Subtotal ................................ ................................ ................ 14.6 70 % Total ................................ ................................ ......................... 21.0 100 %

Areas of operation (as of 12/31/2009, unless otherwise noted) June 24, 2010 Slide 4

AREX investment highlights High quality, long-lived asset base to ride price cycles Low risk, repeatable, multi-year drilling inventory of over 1,300 identified locations Commitment to financial strength Liquidity of $78.4 million Debt-to-capital of 14% Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development Attractive valuation versus peers: EV per proved reserve $0.92/Mcfe 2010 Outlook Increase production in the Permian Basin Strategic acquisitions Bolt-on Opportunistic Balance cash flow with capital spending Increase 2010 - 2011 hedge position June 24, 2010 Slide 5

AREX value proposition AREX $0.92/Mcfe Average $3.98/Mcfe June 24, 2010 Slide 6 Note: EV per Mcfe for all companies is based on 6/21/2010 stock price, 3/31/2010 balance sheet and year-end 2009 proved reserves. Enterprise value per proved reserve ($/Mcfe) $0.92 $1.04 $1.25 $1.86 $2.01 $2.57 $3.68 $3.86 $4.43 $5.05 $5.70 $15.43 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 PETD GMXR GDP CRZO AXAS PQ REXX ROSE CWEI CPE KOG

Future outlook: increase oil & NGL production Begin processing natural gas from Ozona Northeast after 1Q 2011 Processing in Ozona Northeast and continued development in Cinco Terry increase oil and NGL production in 2011 and beyond (6:1 conversion) 10% 19% 28% 29% 46% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 2007 2008 2009 2010-E 2011-E 10% ^ Oil & NGLs (absolute) 117% ^ Oil & NGLs (absolute) June 24, 2010 Slide 7 Oil & NGLs as a % of total production

2010 Capital allocation and guidance 2010 Capital budget of $53 million Allocating 92% to our low-risk, high-return core areas: Ozona Northeast - $25.6 MM, 36 gross (36 net) wells Cinco Terry - $19.9 MM, 48 gross (24 net) wells 2010 Program primarily funded with internally generated cash flow, with use of credit facility as needed 2010 Financial and operating guidance June 24, 2010 Slide 8 Production: Total (MMcfe) ................................ ................................ ............................. 8,900 - 9,400 Operating costs and expenses: Lease operating expense (per Mcfe) ................................ ........................... $ 0.85 - 0.95 Severance and production taxes (percent of oil and gas sales) ................... 5% - 6% Exploration (per Mcfe) ................................ ................................ ................ $ 0.30 - 0.40 General an d administrative (per Mcfe) ................................ ....................... $ 1.05 - 1.15 Depletion, depreciation and amortization (per Mcfe) ................................. $ 2.50 - 3.00

Hedged position Protecting price on 54% of remaining 2010 natural gas production Natural gas & basis differential hedges at 3/31/2010 June 24, 2010 Slide 9 Note: Percent of remaining 2010 natural gas production hedged is based on 1Q 2010 actual production and the midpoint of 2010 production guidance. Volume (MMBtu) $/MMBtu Period Monthly Total Fixed NYMEX - Henry Hub Price swaps 2010 ................................ .............. 150,000 1,350,000 $ 5.85 Price swaps 2010 ................................ .............. 150,000 1,350,000 $ 6.40 Price swaps 2010 ................................ .............. 100,000 900,000 $ 6.36 Weighted average price ($/MMBtu) ............ $ 6.18 WAHA basis differential Basis swaps 2010 ................................ .............. 415,000 3,735,000 $ (0.71 ) Basis swaps 2011 ................................ .............. 300,000 3,600,000 $ (0.53 )

2009 Reserves and unrisked potential 12/31/2009 Proved reserves Prepared by DeGolyer and MacNaughton Category Oil/NGLs (MBbls) Gas (MMcf) Equivalent (MMcfe) June 24, 2010 Slide 10 Proved reserves Developed 74,804 3,118 93,512 Undeveloped 93,530 5,314 125,416 Total proved reserves 168,334 8,432 218,928 Probable reserves 64,161 2,532 79,352 Possible reserves 35,743 1,794 46,504 Total 268,238 12,758 344,785

Historical performance June 24, 2010 Slide 11 CAGR 36.7% CAGR 24.1% Production growth (MMcfe/d) Reserve growth (Bcfe) 4.0 13.7 18.5 19.4 23.9 24.1 0 5 10 15 20 25 30 2004 2005 2006 2007 2008 2009 59.8 108.9 148.8 180.4 211.1 218.9 0 50 100 150 200 250 2004 2005 2006 2007 2008 2009

Historical performance - at a low cost June 24, 2010 Slide 12 AREX $1.79/Mcfe Average $4.91/Mcfe AREX 596% Average 380% 3-Year average F&D costs ($/Mcfe) 3-Year average production replacement (%) 916% 619% 596% 465% 445% 395% 390% 340% 151% 128% 65% 47% 0% 100% 200% 300% 400% 500% 600% 700% 800% 900% 1000% KOG CRZO PETD GDP REXX GMXR AXAS PQ CPE ROSE CWEI $1.73 $1.79 $2.03 $2.47 $3.02 $3.26 $3.43 $4.39 $4.48 $8.07 $10.15 $14.16 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 PETD CRZO AXAS GDP KOG REXX PQ GMXR ROSE CPE CWEI

Low-cost operator AREX $2.40/Mcfe Average $3.33/Mcfe June 24, 2010 Slide 13 Operating and G&A expenses ($/Mcfe) Note: Operating expenses include lease operating expense, production tax and transportation expense. General and administrative (G&A) expense includes stock-based compensation. Operating and G&A expenses per Mcfe for all companies are based on the sum of operating and G&A expenses divided by production for trailing 12 months. $1.87 $1.88 $2.32 $2.40 $2.52 $2.74 $2.83 $3.02 $3.09 $3.62 $6.33 $7.39 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 PQ CRZO GDP ROSE GMXR PETD CWEI CPE AXAS REXX KOG

Recent financial highlights 1Q 2010 highlights (in thousands, except per share amounts) June 24, 2010 Slide 14 Three Months Ended March 31, Variance 2010 2009 (%) Revenues ................................ ................................ .................. $ 13,220 $ 10,065 e 31 % Net income ................................ ................................ ............... $ 3,563 $ 868 e 310 % Net income per diluted share ................................ ................... $ 0.17 $ 0.04 e 325 % Adjusted net income (loss) ................................ ....................... $ 200 $ (548 ) e 136 % Adjusted net income (loss) per diluted share ........................... $ 0.01 $ (0.03 ) e 133 % EBITDAX ................................ ................................ .................... $ 8,987 $ 8,316 e 8 % EBITDAX per diluted share ................................ ........................ $ 0.43 $ 0.40 e 8 % Realized price ($/Mcfe) (excluding commodity derivatives) ...... $ 6.67 $ 3.98 e 68 %

Production rising Estimated average daily production for 2Q 2010 is a 12% increase over 1Q 2010. 2010 Average daily production (MMcfe/d) June 24, 2010 Slide 15 12% ?

Ozona Northeast Proved reserves: 134.8 Bcfe Identified locations: 660 49,850 gross (43,553 net) acres (3/31/2010) AREX operated with ^100% WI and 80% NRI Legacy asset with significant remaining development potential Target formations: Wolfcamp, Canyon Sands, Strawn and Ellenburger Own or operate 140 miles of gathering lines 3-D seismic data covers 53,000 acres across Ozona Northeast June 24, 2010 Slide 16 Block 56 Ozona Northeast Cinco Terry Block 54 Crockett Co Schleicher Co Sutton Co

$7.50/Mcf Ozona Northeast - creating more value Begin processing natural gas production from Ozona Northeast after 1Q 2011 Processing results in $1.25/Mcf potential value added to current revenue stream Key assumptions Commodity prices: $5.00/MMBtu of natural gas $40.00/Bbl of NGLs 1,250 Btu per Mcf Notes: Upon expiration of Ozona Northeast wellhead contract. Potential value added to revenue stream is forward-looking and based on price and other assumptions set forth above. Actual results will vary. Please see forward-looking statements and cautionary statements on page 2 of this presentation. Excludes all costs and effects of transportation, marketing, fuel shrink, line loss and other charges. June 24, 2010 Slide 17 $- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $/Mcf Dry Gas (1,000 Btu) $5.00 $6.25 OZNE - Wet Gas (1,250 Btu) OZNE - Processing Wet Gas $7.50 High BTU Benefit NGL Benefit 25% 20% 1 MMBtu x $5.00 = $5.00/Mcf 1.25 MMBtu x $5.00 = $6.25/Mcf 1 Mcf ^ 0.70 MMbtu (30% shrink) & 0.1 Bbls of NGLs 0.70 MMBtu x $5.00 = $3.50 0.1 Bbls x $40.00 = $ 4.00 April 2011 Current

Ozona Northeast - typical Canyon well Average EUR: 500 MMcfe gross EUR 400 MMcfe net EUR EUR - NGL Processing: 495 MMcfe net EUR Premium price realization: 1,250 Btu per Mcf Wellhead contract Wellhead contract expires after 1Q 2011 ? Begin processing natural gas production and benefit from NGL production Average D&C costs $700k gross Expected breakeven at $2 NYMEX IRR Analysis (500 MMcfe gross EUR) Decline curve ($42/Bbl of NGLs and $75/Bbl of Oil) June 24, 2010 Slide 18 10% 15% 20% 25% 30% 35% 40% $4.50 $5.50 $6.50 $7.00 Gas Price ($/MMBtu) IRR 0 20 40 60 80 100 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Years MMcfe

Cinco Terry Proved reserves: 68.7 Bcfe Identified locations: 558 50,281 gross (23,794 net) acres (3/31/2010) AREX operated with ^52% WI and ^39% NRI Emerging asset with significant growth potential Target formations: Wolfcamp, Canyon Sands and Ellenburger Completed 3-D seismic shoot covering 82,176 acres across Cinco Terry June 24, 2010 Slide 19 Ozona Northeast Cinco Terry Crockett Co

Cinco Terry - typical Canyon well Average EUR: 670 MMcfe gross EUR Premium price realization: 1,220 Btu per Mcf Percent of proceeds contract (93%) Average D&C costs $920k gross Expected breakeven at < $2 NYMEX IRR Analysis (670 MMcfe gross EUR) Decline curve ($42/Bbl of NGLs and $75/Bbl of Oil) June 24, 2010 Slide 20 20% 25% 30% 35% 40% $4.50 $5.50 $6.50 $7.00 Gas Price ($/MMBtu) IRR 0 20 40 60 80 100 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Years MMcfe

Cinco Terry - Ellenburger upside Compelling upside: 1,500 MMcfe gross EUR Premium price realization: 1,220 Btu per Mcf Percent of proceeds contract (93%) Average D&C costs $730k gross IRR Analysis (1,500 MMcfe gross EUR) Decline curve ($42/Bbl of NGLs and $75/Bbl of Oil) June 24, 2010 Slide 21 200% 220% 240% 260% 280% 300% 320% $4.50 $5.50 $6.50 $7.00 Gas Price ($/MMBtu) IRR 0 50 100 150 200 250 300 350 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Years MMcfe

Why invest in AREX? High quality asset base in the Permian Basin Permian Basin production growth from reinvesting cash flow Continued drilling success Multi-stack pay zones Low-cost operator with premium price realization Proven and focused management team June 24, 2010 Slide 22

Appendix Additional properties Non-GAAP and other financial measures

North Bald Prairie Proved reserves: 15.5 Bcfe Identified locations: 93 7,333 gross (4,525 net) acres (3/31/2010) AREX operated with ^50% WI and ^40% NRI Cotton Valley Lime and Cotton Valley Sands development Rodessa and Pettit behind pipe potential June 24, 2010 Slide 24 Approximately 2,641 net acres have been re-leased at ^100% WI North Bald Prairie Limestone Co Robertson Co AMI

North Bald Prairie - typical Cotton Valley well Average EUR: 1,300 - 1,000 MMcfe gross EUR Price realization: 1,050 Btu per Mcf Average D&C costs $2 MM gross IRR Analysis Decline curve (based on 1,300 MMcfe gross EUR) June 24, 2010 Slide 25 0% 10% 20% 30% 40% 50% $4.50 $5.50 $6.50 $7.50 Gas Price ($/MMBtu) IRR 0 50 100 150 200 250 300 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Years MMcfe

Exploratory plays Northern New Mexico - El Vado East Western Kentucky - Boomerang Mancos Shale/Niobrara exploration 2,000 to 3,000 feet 90,357 gross (79,793 net) undeveloped acres (3/31/2010) Proximity to several multi-million barrel fields (mostly crude oil) Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations County ordinance finalized and drilling moratorium lifted 5/2009 Received conditional permits from the County for eight drilling locations Evaluating drilling costs for approved locations, develop drilling plan during 2Q and 3Q 2010 New Albany Shale 74,988 gross (44,759 net) undeveloped acres (3/31/2010) Lease terms (1 year remaining primary + 5 year extensions remaining) provide option value on technology and gas prices Complete two, previously drilled wells in the New Albany Shale in 2010 After evaluating results from test wells, determine development program for the prospect June 24, 2010 Slide 26

Capital efficiency AREX 253% Average 136% June 24, 2010 Slide 27 Low-cost operations and high-quality asset base means superior capital efficiency Note: Capital efficiency for all companies is based on trailing 12 months EBITDAX, divided by trailing 12 months production, divided by 3-year average F&D costs. AREX generated $2.53 in EBITDAX for every $1 of capital expenditures. 268% 253% 214% 146% 142% 136% 108% 101% 97% 92% 46% 33% 0% 50% 100% 150% 200% 250% 300% PETD CRZO KOG AXAS GDP PQ GMXR REXX CPE ROSE CWEI

Asset intensity AREX 36% Average 118% June 24, 2010 Slide 28 A low asset intensity ratio allows more cash flow for growing production and exploring for and developing upside potential Note: Asset intensity for all companies is based on trailing 12 months production multiplied by 3-year average F&D costs, divided by trailing 12 months cash flow from operations. Best-in-class asset intensity to fund future growth. 36% 45% 52% 56% 57% 91% 94% 95% 117% 144% 242% 388% 0% 50% 100% 150% 200% 250% 300% 350% 400% 450% PETD AXAS KOG CRZO PQ REXX GDP GMXR CPE ROSE CWEI

Liquidity and debt-to-capital Liquidity Debt-to-capital Debt-to-capital ratio is calculated as of March 31, 2010, and by dividing long-term debt (GAAP) of $37.2 million by the sum of total stockholders' equity (GAAP) and long-term debt (GAAP) of $261.8 million. We use the debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year to year for the Company and can vary among companies based on what is or is not included in the ratio on a company's financial statements. This ratio 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. Liquidity is calculated as of March 31, 2010, and 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. June 24, 2010 Slide 29 (in thousands) Borrowing base $ 115,000 Cash and cash equivalents 595 Long - term debt (37,169 ) Liquidity $ 78,426

3-Year average F&D costs reconciliation (unaudited) June 24, 2010 Slide 30 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 Mcfe 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 Annual Report on Form 10-K filed with the SEC on March 12, 2010. 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 average finding and development costs for three years ended December 31, 2009 to the information required by paragraphs 11 and 21 of ASC 932-235:

3-Year average F&D costs reconciliation (unaudited) - cont. June 24, 2010 Slide 31 Natural Gas Oil & NGLs Total AREX Historical Reserve Summary (Mmcf) (MBbl) (Mmcfe) Balance - 12/31/2006 98,657 1,122 105,389 Extensions and discoveries 36,194 1,807 47,036 Purchases 40,174 378 42,442 Revisions (9,073) (15) (9,162) Production (4,801) (84) (5,305) Balance - 12/31/2007 161,151 3,208 180,400 Extensions and discoveries 22,879 3,228 42,249 Purchases 7,312 67 7,711 Revisions (11,383) 141 (10,537) Production (7,092) (277) (8,755) Balance - 12/31/2008 172,867 6,367 211,068 Extensions and discoveries 14,301 2,682 30,395 Revisions (12,514) (202) (13,727) Production (6,320) (415) (8,808) Balance - 12/31/2009 168,334 8,432 218,928 Sum of additions and revisions 2009-2007 136,407 AREX Historical Cost Summary (in thousands) 12/31/2009 12/31/2008 12/31/2007 Property acquisition costs Unproved properties 1,081 $ 2,695 $ 5,480 $ Proved properties 57 12,189 59,594 Exploration costs 1,483 5,007 9,897 Development costs 28,121 84,193 37,451 Non-cash asset retirement obligation 170 3,500 - Total 30,572 $ 100,584 $ 112,422 $ AREX F&D Cost ($/Mcfe) AREX Reserve Replacement Ratio Sum of total costs 2009-2007 243,578 $ Sum of additions and revisions 2009-2007 136,407 Sum of additions and revisions 2009-2007 136,407 Sum of production 2009-2007 22,868 3-Year avg. F&D cost 1.79 $ 3-Year avg. reserve replacement ratio 596%

EBITDAX reconciliation (unaudited) (in thousands, except per share amounts) 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. June 24, 2010 Slide 32 Three Months Ended March 31, 2010 2009 Net income $ 3,563 $ 868 Exploration 1,490 - Depletion, depreciation and amortization 5,835 6,948 Share - based compensation 580 679 Unrealized gain on commodity derivatives (5,095 ) ( 2,145 ) Interest expense, net 466 445 Income tax provision 2,148 1,521 EBITDAX $ 8,987 $ 8,316 EBITDAX per diluted share $ 0.43 $ 0.40

Adjusted net income reconciliation (unaudited) (in thousands, except per share amounts) The amounts included in the calculation of adjusted net income (loss) and adjusted net income (loss) 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. June 24, 2010 Slide 33 Three Months Ended March 31, 201 0 2009 Net income $ 3,563 $ 868 Adjustments for certain non - cash items: Unrealized gain on commodity derivatives (5,095 ) (2,145 ) Related income tax effect 1,732 729 Adjusted net income (loss) $ 200 $ (548) Adjuste d net income (loss) per diluted share $ 0.01 $ (0.03 )

Contact Megan P. Brown, Investor Relations 817.989.9000 mbrown@approachresources.com www.approachresources.com