Exhibit 99.1

799. PN at Set SET Exhibit99.1 Company Presentation January 7, 2010 Approach Resources Inc — 01 07 2010 Presentation.pdf

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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 and financial and operating guidance 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. 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 and Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission (“SEC”) on March 13, 2009 and August 7, 2009, respectively. 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 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. The Company uses the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible” and “resource” reserves, reserve “potential,” “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit the Company 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. Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 2

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AREX overview Core areasCore areas of operation operation(1) (1) • Exchange/Ticker • Market cap $160.1 mm(2) • Enterprise value $196.3 mm(3) (1)As of December 31, 2008, unless otherwise noted. (2)Based on December 31, 2009 closing price of $7.72 per share and 20.7 mm shares outstanding and September 30, 2009. January 7, 2010 | 3 Resources Inc — 01 07 2010 Presentation.pdf (3)Net debt at September 30, 2009 was $36.2 mm.

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AREX investment highlights • High quality, long-lived asset base to ride price cycles • Low risk, repeatable, multi-year drilling inventory of over 1,200 identified locations • Financial flexibility to reduce drilling in low-price environment in 2009 and pay down debt • Strong balance sheet heading into 2010: • $115 mm borrowing base • $32.3 mm drawn at 12/31/2009 • Long-term debt-to-capital ratio 14% at 9/30/2009(1) • 2010 guidance midpoint of 25.1 MMcfe/d repr esents a 19% increase in production over October 2009 average daily production of 21.2 MMcfe/d • Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development • Attractive valuation versus peers: Peer comparison — Peer comparison — EV/Mcfe ( EV/Mcfe ($ $/Mcfe) /Mcfe)(2) (2) (1)Long-term debt-to-capital ratio (a non-GAAP measure) definition provided on page 31. (2)Source: publicly-filed company reports. Based on December 31, 2009 closing price of $7.72 per share, September 30, 2009 balance sheet and December January 7, 2010 | 4 Resources Inc — 01 07 2010 Presentation.pdf 31, 2008 reported reserve estimates.

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Proven track record Production growth (MMcfe/d)) Proved reserves growthgrowth (Bcfe) Observations • 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) • Flexibility to decrease capital expenditure budget and still achieve stable production in 2009 (1)Pro forma for the November 14, 2007 acquisition of Neo Canyon Exploration, L.P.’s 30% working interest in Ozona Northeast, as if the acquisition occurred on January 1, 2007. January 7, 2010 | 5 Resources Inc — 01 07 2010 Presentation.pdf (2)Pro forma for the Neo Canyon acquisition.

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Reserve base and unrisked potential Reserve overview Reserve overview(1) (1) Oil/NGLs Gas Equi uivalent Category (MBbls) (MMcf) (MMcfe)) Proved reserves Developed 3,014 84,217 102,298 Undeveloped 3,353 88,651 108,770 Total proved reserves 6,367 172,868 211,068 Probable reserves 2,224 63,240 76,584 Possible reserves 2,084 39,915 52,419 Resource 3,079 73,184 91,658 Total 13,754 349,207 431,729 To Total reserves b by y category Proved reserve mix (1)Estimates of proved, probable and possible reserves at December 31, 2008 are based on an independent engineering study of our oil and gas properties prepared by DeGolyer and MacNaughton. Resource reserve estimates are based on internal Company studies. Probable, possible and January 7, 2010 | 6 Resources Inc — 01 07 2010 Presentation.pdf resource reserves are unrisked and unbooked.

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Reserve growth at a low cost Pe Peer co comp paris ison: Dr Drill—bit F t F& &D cost D cost(1) (1) Peer comparison:Peer comparison: All—in F&D cost(1) (1) 2008 F&D costcost metrics • Drill-bit finding and development cost $2.11/Mcfe • All-in finding and development cost, including revisions $2.64/Mcfe • All-in finding and development cost, including revisions and change in future development costs $2.88/Mcfe (1)Source: publicly-filed company reports. F&D costs (non-GAAP) reconciliation and important disclosures provided on pages 29-30. January 7, 2010 | 7 Resources Inc - 01 07 2010 Presentation.pdf (2)Peer average and peer median metrics for all-in F&D cost exclude peers with a negative all-in F&D cost (GMET, NGAS and REXX).

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AREX: Low-cost producer LOE & severance tax & severance tax(1) (1) (1)Source: LOE and severance tax data for the first 9 mos. of 2009 from publicly-filed company reports. Lease operating expenses include January 7, 2010 | 8 Resources Inc — 01 07 2010 Presentation.pdf

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Positioned to deliver value in 2010 2010 Capital budget 2010 P Prrogram • $53.0 mm capital budget • 2010 guidance of 8,900 MMcfe — 9,400 MMcfe (midpoint 9,150 MMcfe or 25.1 MMcfe/d) • 2010 midpoint represents a 19% increase in production over October 2009 average daily production of 21.1 MMcfe/d • Allocating 86% of the 2010 capital budget to our low-risk, high-return core areas • Ozona Northeast — $25.6 mm • 2 rigs • 36 gross (36 net) wells • Cinco Terry — $19.9 mm • 2 rigs • 48 gross (24 net) wells • 2010 program substantially funded with internally-generated cash flow Hedging to secure capital • • 4 43% of tto o tal 2010 production hedged at aa weighted average price of $ $6. 6.18/Mcfe(1) (1) Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 9 (1)Based on the midpoint of 2010 production guidance. See page 32 for hedging schedule.

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Ozona Northeast Drilling inventory map(1) (1) Key highlights Key highlights(1) (1) • Canyon Sands tight gas, Strawn and Ellenburger development • Own substantially all working interest in all depths • 80% NRI • Legacy asset with significant remaining development potential • 144.4 Bcfe estimated proved reserves, 100% operated at 12/31/2008 • Low decline rates (4%-6%) in mature wells • 49,169 gross (43,180 net) acres • Own or operate 140 miles of gathering lines • 660 identified drilling locations at 12/31/2008 • Evaluating reprocessed 3-D seismic to identify Strawn and Ellenburger targets Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 10 (1)As of September 30, 2009, unless otherwise noted.

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Ozona Northeast: typical Canyon well Key observations DeclineDecline curve • Statistical, predictable results • 520 — 480 MMcfe average gross EUR • 396 — 366 MMcfe average net EUR (80% NRI) • Premium price realization driven by high gas heat content • 1,250 Btu per Mcfe • Make-whole contract (wellhead) • Contract expires 2/2011 • Expected D&C costs $670k per well (8/8th) • Expected breakeven at $3.50 NYMEX Price (NYMEX), IRR & Payout IRR Analysis (520 MMcfe EUR) & • Based on 520 MMcfe average gross EUR ($ /MMBtu) IRR Pa yout (y rs) $4.50 14% 5.4 $5.50 19% 3.9 $6.50 25% 3.1 $7. 50 32% 2.4 • Oil $70/Bbl, NGLs $32.50/Bbl Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 11

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Cinco Terry Drilling inventory map(1) (1) Key highlights Key highlights(1) (1) • Canyon Sands tight gas development • #}52% WI & 39% NRI • Ellenburger development • 45.9 Bcfe estimated proved reserves at 12/31/2008 • 48,893 gross (22,899 net) acres • 456 identified drilling locations at 12/31/2008 • Began 3-D seismic shoot Multiple horizonon potential Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 12 (1)As of September 30, 2009, unless otherwise noted.

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Cinco Terry: 3-well cross section 3-Well3-Well cross section map University 42-13 5 University 45-29 1 Baker B 201 Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 13

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Cinco Terry: 3-well cross section A’ Baker B 201 University 45-29 1 University 42-13 5 TD : 8,620’ TD : 8,100’ TD : 8,100’ ELEV KB : 2,637’ ELEV KB : 2,617’ ELEV KB : 2,630’ 12,469’ 11,538’ RT90 0.2 2,000 MSFL MSFL RT60 0.2 2,000 0.2 2,000 0.2 2,000 GR GR GR RT30 APF LLD NPHI LLD NPHI 0 200 0 200 0 200 0.2 2000 0.3 -0.1 0.2 2,000 0.3 -0.1 0.2 2,000 0.3 -0.1 CALI LLS DPHI CALI LLS DPHI CALI RT20 DPHI 6 16 0.2 2,000 0.3 -0.1 6 16 0.2 2,000 0.3 -0.1 6 16 0.2 2000 0.3 -0.1 Ozone Top 7,700’ 7,700’ 7,700’ Shale 7,800’ Sand 7,800’ 7,800’ 7,900’ Gas-Filled 7,900’ 7,900’ Porosity 8,000’ 8,000’ 8,000’ Gas-Filled Porosity ~ 112’ Gas-Filled Porosity ~ 120’ Gas-Filled Porosity ~ 50’ Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 14

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Cinco Terry: typical Canyon well Key observations DeclineDecline curve • Statistical results • #}52% WI & 39% NRI • 547 MMcfe average gross EUR • 258 MMcfe average net EUR • Premium price realization driven by high gas heat content • 1,220 Btu per Mcfe • 93% POP contract • Expected D&C Costs $810k per well (8/8th) • Expected breake ven at $3.00 NYMEX Price (NYMEX), IRR & Payout IRR Analysis (547 MMcfe EUR) & • Based on 547 MMcfe average gross EUR ($ /MMBtu) IRR Payout (yrs) $ 4.50 29% 2.5 $5.50 32% 2.3 $6.50 35% 2.1 $7.50 38% 1.9 • Oil $70/Bbl, NGLs $32.50/Bbl Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 15

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Cinco Terry: typical Canyon/Ellenburger well Key observations DeclineDecline curve • Statistical results • #}52% WI & 39% NRI • 653 MMcfe average gross EUR • 311 MMcfe average net EUR • Premium price realization driven by high gas heat content • 1,220 Btu per Mcfe • 93% POP contract • Expected D&C costs $860k per well (8/8th) • Expected breakeven less than $3.00 NYMEX Price (NYMEX), IRR & Payout IRR Analysis (653 MMcfe EUR) & • Based on 653 MMcfe average gross EUR ($ /MMBtu) IRR Payout (yrs) $4.50 25% 2.5 $5.50 27% 1.9 $6.50 28% 1.8 $7. 50 30% 1.8 • Oil $70/Bbl, NGLs $32.50/Bbl Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 16

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Cinco Terry: Ellenburger upside Key observations DeclineDecline curve • Statistical results • #}52% WI & 39% NRI • 1,315 MMcfe average gross EUR • 670 MMcfe average net EUR • Premium price realization driven by high gas heat content • 1,220 Btu per Mcfe • 93% POP contract • Expected D&C costs $670k per well (8/8th) Price (NYMEX), IRR && Payout IRR Analysis (1,315 MMcfe E EU U R) • Based on 1,315 MMcfe average gross EUR ($ /MMBtu) IRR Payout (yrs) $4. 50 210% 0.4 $5. 50 234% 0.3 $6.50 258% 0.3 $7.50 281% 0.3 • Oil $70/Bbl, NGLs $32.50/Bbl Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 17

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Cinco Terry 3-D seismic area 3-D seismic area Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 18

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North Bald Prairie Drilling inventory map(1) (1) Key highlights Key highlights(1) (1) • Cotton Valley Lime, Bossier Shale, Cotton Valley Sands development • 50% WI & #}40% NRI • 20.8 Bcfe estimated proved reserves at 12/31/2008 • 7,846 gross (3,240 net) acres • Approximately 3,115 gross (2,026 net) acres have been re-leased at substantially 100% WI as of 11/30/2009 • 89 locations identified at 12/31/2008 • Rodessa and Pettit behind pipe potential Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 19 (1)As of September 30, 2009, unless otherwise noted.

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North Bald Prairie: typical Cotton Valley well Key observations DeclineDecline curve • Statistical results 50% WI & 40% NRI • #} • 1,300 — 1,000 MMcfe average gross EUR • 507 — 400 MMcfe average net EUR • Price realization • 1,050 Btu per Mcfe • Expected D&C costs $2.0 mm per well (8/8th) Price (NYMEX), IRR && Payout IRR Analysis (1,300 MMcfe EUR) EUR) • Based on 1,300 MMcfe average gross EUR ($ /MMBtu) IRR Payout (yrs) $4.50 9% 6.5 $5.50 18% 3.9 $6.50 28% 2.7 $7. 50 39% 1.9 Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 20

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Exploratory plays British Columbia Northern New Mexico — Northern New Mexico — El VadoEl Vado East • 25% non-operated WI • Mancos Shale exploration • 31,231 gross (7,395 net) acres at 9/30/2009 • 2,000 to 3,000 feet • Primary targets are Doig shale, Montney tight • 90,357 gross (79,793 net) undeveloped acres gas sands and lower Montney shale at 9/30/2009 • Proximity to several multi-million barrel fields (mostly crude oil) Western Kentucky — B Boomerang • Additional prospectivity in Dakota, Morrison, Todilto and Entrada formations • New Albany Shale • County ordinance finalized and drilling moratorium lifted 5/2009 • 74,988 gross (44,759 net) undeveloped acres at 9/30/2009 • Expect to begin drilling summer 2010 • Lease terms (1 year remaining primary + 5 year extensions remaining) provide option value on technology and gas prices • After evaluating results from test wells, determine development program for the prospect Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 21

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AREX investment highlights • High quality, long-lived asset base to ride price cycles • Low risk, repeatable, multi-year drilling inventory of over 1,200 identified locations • Financial flexibility to reduce drilling in low-price environment in 2009 and pay down debt • Strong balance sheet heading into 2010: • $115 mm borrowing base • $32.3 mm drawn at 12/31/2009 • Long-term debt-to-capital ratio 14% at 9/30/2009(1) • 2010 guidance midpoin t of 25.1 MMcfe/d represents a 19% increase in production over October 2009 average daily production of 21.2 MMcfe/d • Technically driven management team with a proven track record of unconventional resource exploration, evaluation and development • Attractive valuation versus peers 2010 Outlook Outlook 9 Focus on increasing production in core operating areas in the Permian 9 Strategic acquisitions • Bolt-on and PDP-weighted • Opportunistic 9 Balance cash flow with capital spending 9 Increase 2010 — 2011 hedge position Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 22 (1)Long-term debt-to-capital ratio (a non-GAAP measure) definition provided on page 31.

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Appendix

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Financial and operating guidance 2009 && 2010 financial and operating guidance financial and operating guidance The table below sets forth the Company’s current 2009 and 2010 financial and operating guidance. The 2009 and 2010 guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control, as further described on page 2 of this presentation. 2009 2010 Guidance Guidance Production: Total (MMcfe) 8,700 — 9,000 8,900 — 9,400 Operating costs and expenses: Lease operating expense (per Mcfe) $ 0.85 — 0.95 $0.85 — 0.95 Severance and production taxes (percent of oil and gas sales) ... 5% — 6% 5% — 6% General and administrative (per Mcfe) $1.00 — 1.10 $1.05 — 1.15 Depletion, depreciation and amortization (per Mcfe) $2.50 — 3.00 $2.50 — 3.00 Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 24

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Equity ownership OwnershipOwnership of management &management & certain beneficialbeneficial ownersowners at 9/30/2009 Number of Shares of Common Stock Owned (mm) Percent Management and Affiliates Yorktown Energy Partners . 6.6 32% Lubar Equity Fund, LLC 0.9 4% Officers, directors and employees 1.5 8% Subtotal 9.0 44% Public Float 5% Beneficial owners(1) . 1.9 9% Other stockholders 9.8 47% Subtotal 11.7 56% Total . 20.7 100% Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 25 (1)As of most recent public filings, 1.9 million shares are owned by non-affiliate holders of 5% or more of our outstanding common stock.

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Financial and operating data (unaudited) $ $ thousands,thousands, except per—unit metrics Three Months Ended Nine Months Ended September 30, September 30, 2009 2008 2009 2008 Revenues (in thousands): Gas ... $5,001 $14,456 $16,936 $47,900 Oil ... 2,490 5,973 7,700 13,223 NGLs 1,296 1,586 4,131 4,054 Total oil and gas sales . $8,787 $22,015 $28,767 $65,177 Realized gain (loss) on commodity derivatives ... ... 4,271 (195) 11,896 (676) Total oil and gas sales including derivative impact $13,058 $21,820 $40,663 $64,501 Production: Gas (MMcf) 1,505 1,588 4,900 4,927 Oil (MBbls) 39 54 155 120 NGLs (MBbls) 44 28 164 75 Total (MMcfe) 2,003 2,080 6,817 6,097 Total (MMcfe/d).. 21.8 22.6 25.0 22.3 Average prices: Gas (per Mcf) $3.32 $ 9.10 $3.46 $9.72 Oil (per Bbl) 63.49 110.61 49.53 110.19 NGLs (per Bbl) ... 29.72 56.64 25.18 54.05 Total (per Mcfe) ... $4.39 $10.58 $4.22 $10.69 Realized gain (loss) on commodity derivatives (per Mcfe) 2.13 (0.09) 1.75 (0.11) Total including derivative impact (per Mcfe) ... $ 6.52 $10.49 $5.97 $10.58 Costs and expenses (per Mcfe): Lease operating ... $0.95 $0.89 $ 0.88 $0.84 Severance and production taxes 0.23 0.47 0.20 0.47 Exploration .. 0.27 ¯ 0.08 0.24 General and administrative ... 1.12 0.92 1.07 0.93 Depletion, depreciation and amortization 2.79 2.41 2.75 2.67 EBITDAX(1) $8,886 $17,391 $27,412 $51,629 Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 26 (1)EBITDAX (a non-GAAP measure) reconciliation provided on page 28.

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Condensed balance sheet data (unaudited) $ $ thousands thousands September 30, December 31, Unaudited Consolidated Balance Sheet Data (in thousands): 2009 2008 Cash and cash equivalents $ 700 $4,077 Other current assets 7,509 30,760 Property and equipment, net, successful efforts method 304,104 303,404 Other assets 220 ¯ Total assets $312,533 $338,241 Current liabilities $9,199 $30,775 Long-term debt 36,939 43,537 Other long-term liabilities 43,965 40,116 Stockholders’ equity 222,430 223,813 Total liabilities and stockholders’ equity $312,533 $ 338,241 January 7, 2010 | 27

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EBITDAX reconciliation (unaudited) $ $ thousands,thousands, except per-shareper-share metrics Three Months Ended Nine Months Ended September 30, September 30, 2009 2008 2009 2008 Net (loss) income $ (3,144) $19,848 $ (2,947) $23,538 Exploration 534 ¯ 534 1,478 Depletion, depreciation and amortization 5,595 5,016 18,766 16,257 Share-based compensation 414 304 1,434 800 Unrealized loss (gain) on commodity derivatives 6,414 (18,611) 8,589 (4,060) Interest expense, net 451 423 1,353 914 Income tax (benefit) provision (1,378) 10,411 (317) 12,702 EBITDAX $8,886 $17,391 $ 27,412 $51,629 EBITDAX per diluted share $0.42 $0.83 $1.31 $2.48 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) 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. Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 28

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Finding & development costs reconciliation (unaudited) 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 and Quarterly Reports on Form 10-Q filed with the SEC on March 13, 2009, May 6, 2009 and August 7, 2009, respectively. 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 for the year ended December 31, 2008 to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69: January 7, 2010 | 29

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F&D costs reconciliation (unaudited) — cont. Reconc onciliation Definitions Definitions Cost summary (in thousands) • Drill-bit finding and development (“F&D”) costs Property acquisition costs Unproved properties $2,695 are calculated by dividing the sum of exploration Proved properties ,189 12 costs and development costs for the year, by the Exploration costs 007 5, total of reserve extensions and discoveries for the Development costs(1) 84,193 year. Total costs incurred $104,084 • All-in F&D costs, including revisions, are Future development costs (in thousands) calculated by dividing the sum of property 2007 $19 1,738 2008 20 1,259 acquisition costs, exploration costs and Change in future development costs $9,521 development costs for the year, by the total of reserve extensions, discoveries, purchases and all Reserve summary (MMcfe) revisions for the year. Balance¯December 31, 2007 0,400 18 Extensions and discoveries ,249 42 • All-in F&D costs, including revisions and the Purchases of minerals in place ,711 7 change in future development costs, are Production (8 ,755) Revisions to previous estimates 10,537 () calculated by dividing the sum of property Balance¯December 31, 2008 211,068 acquisition costs, exploration costs, development costs and the change in future development costs Finding and development costs ($/Mcfe) from the prior year, by the total of reserve Drill-bit finding and development cost $ .11 2 All-in finding and development cost, including extensions, discoveries, purchases and all revisions $2.64 revisions for the year. All-in finding and development costs, including revisions and change in future development costs $2.88 Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 30 (1) Includes $3.5 million in non-cash asset retirement obligations recorded in 2008.

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Long-term debt-to-capital ratio (unaudited) Long-term debt-to-capital is calculated as of September 30, 2009, and by dividing long-term debt (GAAP) of $36.9 million by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP) of $259.4 million. We use the long-term 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.

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Hedging positions at 12/31/2009 2010 Natural gas hedges Volume (MMBtu) $/MMBtu Percent of 2010 Period Monthly Total Fixed Production(1) NYMEX — Henry Hub Fixed price swaps 2010 . 150,000 1,800,000 $5.85 16% Fixed price swaps 2010 . .. . .. 150,000 1,800,000 $6.40 16% Fixed price swaps 2010 .. .. 100,000 1,200,000 $6.36 11% Total 43% Weighted average price ($/Mcf) $ 6.18 WAHA differential Fixed price swaps 2010 . .. .. .. 415,000 4,980,000 $ (0.71) 45% 2011 Natural gas hedges • We also have a basis swap at $(0.53) per MMBtu for 300,000 MMBtu per month for 2011. Resources Inc — 01 07 2010 Presentation.pdf January 7, 2010 | 32 (1)Percent of estimated production hedged for 2010 is based on the midpoint of total 2010 production guidance, or 9,150 MMcfe.