Exhibit 99.1

Rodman & Renshaw Annual Global Investment Conference SEPTEMBER 12, 2011

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Forward-looking statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words "will," "potential," "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," "target," "profile," "model," or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K for the year ended December 31, 2010. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The Securities and Exchange Commission ("SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms "estimated ultimate recovery" or "EUR," reserve 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 our 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 and well 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. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. Cautionary statements regarding oil and gas quantities

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Approach Resources Inc. Notes: Proved reserves and acreage as of 6/30/2011. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing price of $18.44 per share on 8/9/2011, plus net debt as of 6/30/2011. Liquidity calculation provided under "Financial Framework." AREX OVERVIEW ASSET OVERVIEW Enterprise value $617.3 MM High quality reserve base 66.8 MMBoe proved reserves 97% Permian Basin 55% Oil & NGLs Permian core operating area 158,700 gross (140,400 net) acres 500+ MMBoe gross, unrisked resource potential Extensive inventory of drilling and recompletion opportunities Strong balance sheet to execute plan Liquidity $106.9 MM

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2Q 2011 Highlights 2Q 2011 FINANCIAL HIGHLIGHTS Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, 2011 2011 2010 2010 Revenues ($M) $ 29,123 $ 13,155 Net income ($M) $ 7,990 $ 1,551 Net income per diluted share $ 0.28 $ 0.07 Adjusted net income (non-GAAP) ($M) $ 6,516 $ 2,806 Adjusted net income per diluted share $ 0.23 $ 0.13 EBITDAX (non-GAAP) ($M) $ 20,999 $ 10,345 EBITDAX per diluted share $ 0.73 $ 0.49 Realized price ($/Boe) $ 47.90 $ 35.36 Production (MBoe/d) 6.7 4.1 Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively. Realized price excludes commodity derivatives. AREX 2Q 2011 SUMMARY 7th Consecutive quarter of production growth 2Q'11 production 6.7 MBoe/d Proved reserves increase 32% to 66.8 MMBoe Oil & NGL reserves increase 44% to 36.9 MMBbls Reserve mix now 55% oil & NGLs Improving well results from horizontal Wolfcamp pilot program Horizontal Wolfcamp and vertical Wolffork plays add over 500 MMBoe of gross, unrisked resource potential On track to meet production target of 2,300 MBoe - 2,450 MBoe Targeting 50%+ production growth

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2Q 2011 Operating Highlights DELIVERING Q/Q PRODUCTION GROWTH OPERATING HIGHLIGHTS (CHART) production (mboe/d) 56% oil & ngls Q2'11 production up 63% to 6.7 MBoe/d Oil & NGL production up 203% to 340 MBbls Drilled 15 wells, completed 16 wells, and 5 wells waiting on completion Horizontal Wolfcamp well results University 45 A 701H - 6,859' lateral, 21 frac stages Initial 24-hour flow rate 693 BOEPD, 94% liquids (613 BO, 41 Bbls NGLs, 237 Mcf gas) Cinco Terry G 701H - 7,609' lateral, 23 frac stages Initial 24-hour flow rate 328 BOEPD, 76% liquids (168 BO, 81 Bbls NGLs, 473 Mcf gas)

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(CHART) (CHART) Note: 2011E production and production mix based on the midpoint of production guidance. See "F&D Costs Reconciliation" slide in appendix for reconciliation. Track Record of Reserve and Production Growth RESERVE GROWTH PRODUCTION GROWTH MY'11 proved reserves up 32% to 66.8 MMBoe Oil & NGL reserves up 44% to 36.9 MMBbls 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 Balanced production mix in 2011 and beyond 98% Permian Basin 2011 targets: 50%+ Production growth 55% Oil and NGLs; 45% natural gas production mix 55% oil & ngls 55% oil & ngls proved reserves (mmboe) production (mboe/d) 2004-2011E CAGR: 46% 2004-MY'11 CAGR: 34%

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Midland Basin Delaware Basin Central Basin Platform Northwest Shelf Eastern Shelf Wolffork Play 250 miles by 300 miles 1st commercial oil accumulation (Westbrook) discovered in 1921 Over 30 billion barrels of oil produced over last 90 years Largest oil and gas producing area in Lower 48 Over 1,300 oil reservoirs and 30 plays identified Approximately 80% of producing reservoirs <10,000' Over 450 US rigs are active in Permian Source: USGS, Bureau of Economic Geology, Baker Hughes and IHS. Permian Basin - World Class Petroleum Basin PERMIAN BASIN

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AREX Acreage Position - Favorably Located in the Permian Basin

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AREX Acreage Position - Permian Basin Large, primarily contiguous acreage position 158,700 gross (140,400 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) Significant potential reserves 500+ MMBoe gross, unrisked reserve potential 2,900+ potential horizontal, vertical and recompletion targets Additional upside potential in downspacing opportunities 2011 Program - 2 vertical rigs and 1 horizontal rig $130 MM drilling and development budget 1 horizontal Wolfcamp rig, 1 vertical Wolffork rig, 1 vertical Canyon/Ellenburger rig De-risk acreage position with horizontal and vertical pilot program Acquire 3-D seismic data Dean Clearfork /Spraberry Wolfcamp Cisco Canyon Ellenburger Strawn San Andres Grayburg 2,500' gross pay Southern Midland Basin Val Verde Basin Ozona Arch Tight sand Target Carbonate Carbonate Shale Shale Wolffork Shale AREX DRILLING TARGETS

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Wolffork Oil Shale Resource Play Sutton Crockett Irion Reagan Schleicher Pangea West Northern & Central Pangea 59,000 gross acres Continue pilot program Encouraging results from recent pilot wells 85,000 gross acres Begin vertical development (from pilot) Establish horizontal development Southern Pangea 15,000 gross acres 3-D seismic underway Begin horizontal drilling 4Q 2011 Vertical pilot - 2nd phase Horizontal pilot Horizontal drilling in progress Horizontal on drilling order Drilling depth to top of Wolfcamp Legend

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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 (CHART) VERTICAL WOLFFORK BTAX IRR SENSITIVITIES 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. 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

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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 on 20 to 40 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price. (CHART)

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(CHART) Vertical Wolffork Well Profile Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well 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. IRR estimates assume NYMEX forward-curve 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. IP Profile 58 BO, 11 Bbls NGLs, 64 Mcf gas Avg. EUR 110 MBoe Annual Decline 62% 29% 20% 15% 12% 10% 9% 8% 7% 6%

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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 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. 1 active rig in Pangea (CHART)

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(CHART) Vertical Canyon Wolffork Well Profile Annual Decline 68% 32% 21% 16% 12% 10% 9% 8% 7% 6% Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well 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. IRR estimates assume NYMEX forward-curve 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. IP Profile 66 BO, 52 Bbls NGLs, 315 Mcf gas Avg. EUR 193 MBoe

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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 (Bbls) 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

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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 (CHART) 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.

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(CHART) Horizontal Wolfcamp Well Profile Annual Decline 62% 31% 21% 16% 13% 11% 9% 8% 7% 6% Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well 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. IRR estimates assume NYMEX forward-curve 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. IP Profile 230 BO, 47 Bbls NGLs, 285 Mcf gas Avg. EUR 450 MBoe

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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 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well 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. IRR estimates assume NYMEX forward-curve 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.

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Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich plays 140,400+ net, primarily contiguous acres, 100% operated More than 525 wells drilled by Approach since 2004, with a 93%+ success rate Established basin infrastructure Strong growth track record at competitive costs Historical production and reserve growth driven by Canyon Sands liquids-rich gas play Future growth from vertical Wolffork and horizontal Wolfcamp plays Low-cost operator with best-in-class F&D and lifting costs Developing significant resource potential from vertical Wolffork and horizontal Wolfcamp plays Gross, unrisked resource potential totals more than 500+ MMBoe Additional upside potential from down-spacing opportunities Strong balance sheet to execute development plan $106.9 MM of liquidity at 6/30/2011 Note: Liquidity calculation provided under "Financial Framework." Key Takeaways

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Financial Framework

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Current 2011 Guidance Current 2011 Guidance Current 2011 Guidance Current 2011 Guidance Production Total (MBoe) 2,300 - 2,450 2,300 - 2,450 2,300 - 2,450 Percent Oil & NGLs 55% 55% 55% Operating costs and expenses ($/per Boe) Lease operating $ 4.25 - 5.50 4.25 - 5.50 4.25 - 5.50 Severance and production taxes $ 2.35 - 3.00 2.35 - 3.00 2.35 - 3.00 Exploration $ 4.00 - 5.00 4.00 - 5.00 4.00 - 5.00 General and administrative $ 6.25 - 6.75 6.25 - 6.75 6.25 - 6.75 Depletion, depreciation and amortization $ 12.00 - 15.00 12.00 - 15.00 12.00 - 15.00 Capital expenditures ($MM) Approximately $220 Approximately $220 Approximately $220 2011 Operating and Financial Guidance

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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 (1) Based on midpoint of 2011 production guidance. 2011 Hedge Position CURRENT HEDGE POSITION

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(in thousands) Liquidity at June 30, 2011 Liquidity at June 30, 2011 Borrowing base $ 200,000 Cash and cash equivalents 831 Long-term debt (93,550) Unused letters of credit (350) Liquidity $ 106,931 Liquidity CURRENT LIQUIDITY POSITION (UNAUDITED)

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Appendix Non-gaap reconciliations

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(in thousands, except per-share amounts) Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, 2011 2011 2010 2010 Net income $ 7,990 $ 1,551 Adjustments for certain items: Unrealized (gain) loss on commodity derivatives (2,231) 1,901 Gain on sale of oil and gas properties (3) ^ Related income tax effect 760 (646) Adjusted net income $ 6,516 $ 2,806 Adjusted net income per diluted share $ 0.23 $ 0.13 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)

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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. (in thousands, except per-share amounts) Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, 2011 2011 2010 2010 Net income $ 7,990 $ 1,551 Exploration 280 187 Depletion, depreciation and amortization 7,987 5,010 Share-based compensation 1,713 416 Unrealized (gain) loss on commodity derivatives (2,231) 1,901 Gain on sale of oil and gas properties (3) ^ Interest expense, net 863 550 Income tax provision 4,400 730 EBITDAX $ 20,999 $ 10,345 EBITDAX per diluted share $ 0.73 $ 0.49 EBITDAX Reconciliation (Unaudited)

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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 to be included in our Annual Report on Form 10-K and to be filed with the SEC on or before March 15, 2012. 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) Reserve Summary (MBoe) Balance - 12/31/2010 50,715 Extensions & discoveries 8,910 Purchases 10,497 Revisions (2,196) Production (1,077) Balance - 6/30/2011 66,849 Cost Summary ($M) Property acquisition Unproved properties $ 15,440 Exploration properties 93 93 Exploration costs 4,914 4,914 Development costs 72,061 72,061 Working Interest Acquisition 70,181 70,181 Total 162,689 162,689 Finding & development costs ($/Boe) Finding & development costs ($/Boe) Finding & development costs ($/Boe) All-in F&D costs $ 9.45 Drill-bit F&D cost $ 8.64 Reserve replacement ratio (%) Reserve replacement ratio (%) Reserve replacement ratio (%) Net reserve adds (MBoe) 17,211 1H'11 Production (MBoe) (1,077) Reserve replacement 1,598%