Corporate Presentation

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1 Corporate Presentation September 10, 2009 (NYSE Amex: EPM) Evolution Petroleum Corporation 1

2 Evolution Petroleum Corporation This presentation contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act. Forwardlooking statements give our current expectations or forecasts of future events. They include statements regarding g our future operating and financial performance. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. You should understand that the following important factors, could affect our future results and could cause those results or other outcomes to differ materially from those expressed or implied in the forward-looking statements relating to: (1) amount, nature and timing of capital expenditures; (2) drilling of wells and other planned exploitation activities; (3) timing and amount of future production of oil and natural gas; (4) increases in production growth and proved reserves; (5) operating costs such as lease operating expenses, administrative costs and other expenses; (6) our future operating or financial results; (7) cash flow and anticipated liquidity; (8) our business strategy, and the availability of acquisition opportunities; (9) hedging strategy; (10) exploration and exploitation activities and property acquisitions; (11) marketing of oil and natural gas; (12) governmental and environmental regulation of the oil and gas industry; (13) environmental liabilities relating to potential pollution arising from our operations; (14) our level of indebtedness; (15) timing and amount of future dividends; (16) industry competition, conditions, performance and consolidation; (17) natural events such as severe weather, hurricanes, floods, fire and earthquakes; and (18) availability of drilling rigs and other oil field equipment and services. Wecautionyounottoplaceunduerelianceontheseforward-looking statements, which speak only as of the date of this presentation or as of the date of the report or document in which they are contained, and we undertake no obligation to update such information. The filings with the SEC are hereby incorporated herein by reference and qualifies the presentation in its entirety. 2

3 Evolution Petroleum Corporation Cautionary Note to U.S. Investors Regarding Oil and Gas Reserve Estimates: The U.S. Securities and Exchange Commission permits oil and gas companies, in their current 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 is currently prohibited from disclosing other categories of reserves in its SEC filings. We use certain terms in this press release such as "Probable or Possible oil and gas reserves that the SEC s guidelines strictly prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the disclosure in our SEC filings, available from us at 2500 City West Blvd, Suite 1300, Houston, Tx 77042; Telephone: You can also obtain these filings from the SEC by calling SEC The reserve quantities reflected above were certified by W. D. Von Gonten & Company using the 1997 definitions and standards of the Society of Petroleum Engineers and World Petroleum Congresses. These definitions and standards may result in estimates of proved reserves which are materially different from those disclosed in the Company s filings with the SEC. NOTE: ALL REFERENCES HEREIN TO PV-10 REFLECT SEC PRICING UNLESS NOTED AS ESCALATED. 1P = Proved 2P = Probable 3P = Possible 3

4 Our Business We generate & implement projects that develop oil and natural gas reserves: That are located in the onshore US, Are generally well known, but bypassed historically due to low commodity prices or lack of applied technology, Based on a low risk, engineered approach, and Utilize our expertise and technology Since the staff of EPM owns 20% of the company on a fully diluted basis, we are very focused on protecting and improving share value. 4

5 O&G Core Assets (Net Reserves at 7/1/09) East OK Shale 17,600 net acres Low cost, shallow gas Delhi Field 13.6 MMBO 2P CO 2 -EOR 100% oil Neptune Project 0.5 MMBO 1P+2P+3P + 79 additional locations All infill oil locations Giddings Field 3.0 MMBOE 1P 0.9 MMBOE 2P 30% oil, 35% NGL, 35% gas 14% PDP 5

6 EPM Investment Highlights Why Own EPM? 6

7 EPM Investment Highlights Consistent growth in revenues Strong balance sheet with no debt 1P & 2P reserves 84% oil & 7% NGL; long term upside in low cost gas resource Sufficient cash resources in hand to fund 2010 capital expenditure program Low cost & low risk development upside Opportunity to realize embedded asset valuation in all projects Value in Delhi driven by time capex carried by DNR & production begins 2010 Proprietary Technology -? OK Shales -? Working Capital - $.21 EPM s PV-10 per Fully Diluted Share Giddings - $1.44 (1P + 2P) Neptune - $.25+ (1P+2P+3P) Delhi - $6.05 (2P) 7

8 EPM Track Record in Project Development Engineering driven origination & high value creation Project Delhi EOR Neptune Oil OK Shale Giddings Artificial i Lift Tech Invested: $6.8 MM $0.6 MM $5.5 MM $26.5 MM $0.2 MM Results $50 MM cash pretax + 2P Reserves PV-10 = $196 MM 2P PV-10 peak (2015) ~ $290 MM 1P 3P Reserves PV-10 = $8.1 MM & 79 additional locations pending up to 200+ BCF potential $7 MM cash from field, + 4 MMBOE of 1P-2P reserves PV-10 = $46 MM First field test t successful to date 8

9 EPM Reserves by Fiscal Year Proved 8 Giddings 2P Delhi 2P 6 Neptune 1P-3P Reserves as at fiscal year end of June 30 Does not include low cost shale gas resource in Oklahoma & additional Neptune locations 2009 downward revisions due to commodity price changes (from ~$140/BO to ~$70/BO & $13.09/MMBTU to ~$3.88/MMBTU) FYE 06 proved reserves decreased by farm-out of Delhi working interest 9

10 EPM Revenues Growth by Fiscal Year Revenues in thousands 2007 revenues decreased by farm-out to DNR 10

11 FY 2010 Capital Plan Objectives: Substantially expand proved reserves Neptune (South Texas) oil project Oklahoma gas shales Begin to commercialize artificial lift technology Giddings cash income to cover overhead Avoid use of high cost, risky capital sources Maintain liquidity through FY2011 when Delhi cash flows are projected to substantially increase use $3MM of our liquidity in FY2010 to leverage activity 11

12 FY2010 Plan for Growth OK: Continued gas shale testing of up to 200 BCF potential Delhi: DNR funds expansion of our CO 2 -EOR project Neptune: Drill first 2 oil wells Target quadrupling of current 500 MBO of 1P-3P reserves Giddings: Maintain production Joint ventures to drill PUDs Joint ventures to apply our proprietary artificial lift tech. 12

13 EPM Assets: Delhi CO2 EOR Project 13

14 EOR - Delhi Field CO 2 Project 7/1/09 Pb Net Reserves 13.6 MMBO $196 MM PV-10 Delhi Tinsley Jackson Dome Gross Production to date 190 MMBO Original oil in pace place est. 357 MMBO ( OOIP ) in swept portion Average depth 3,235 Size 13,636 acres Formations Tuscaloosa & Paluxy Reserves Basis Analogous Tinsley Field, ample subsurface control, pilot projects in same field, committed proved CO 2 reserves, pipeline completed & tested, & available funding for balance of project 14

15 Delhi Field Development by EPM & DNR Hi igh RO IC Addition nal Valu ue (Calendar year) 2003: Purchased working interest in Delhi Field for $2.8 million 2004: Increased production from 20 bopd to ~145 boep/d through ~$2.5 million of capex 2006: Sold farm-out to DNR for $50 MM - retained 25% reversionary working interest after payout. Acquired additional 7.4% royalty interests for $1.5 MM : DNR invests ~$342MM EPM earning minimal revenues from royalty interest t 2010: EOR production projected; royalty interest cash flow begins to grow : DNR invests additional ~$122MM to complete project 2014: Independent reservoir engineer projects $200 million payout to occur, based on flat $66 oil price; 25% WI (20% NRI) reverts to EPM 15

16 EOR Expands EPM s Reserve Base & Value Denbury s EOR project could recover up to 19% of original oil in place (OOIP) at Delhi Field (based on DNR s historic results), compared to the 15% assigned in 2P reserves. Additional 4% recovery could add 3.8 MMBO to EPM s net reserves. EPM s 25% reversionary working interest commences after DNR generates ~$200 million in revenues less operating expenses, and is not affected by actual amount of capital expenditures by DNR. Delhi PV-10 vs. Gross Recovery, % OOIP (at $60 oil + 3% escalation) %ofsweptooip 20% Delhi PV-10 vs. NYMEX Oil Price in 2010 (15% Recovery & 3% escalation) $/bbl $100 15% $50 10% $4 $6 $8 $10 $12 NPV-10 per fully diluted share $- $- $4 $8 $12 NPV-10 per fully diluted share 16

17 Impact of Delhi Production* Annual Net Cash Flows from Delhi per fully diluted share Gross Field Production = 1,000 BOPD 2,460 BOPD 5,600 BOPD 7,880 BOPD 10,000 BOPD < Payout Occurs > Pre & Post Payout 7.4% Royalty Interest = $0.05 $0.12 $0.27 $0.38 $0.48 After Payout 25% Reversionary WI = $0.63 $1.00 Annual Net Cash Flows per Fully Diluted Share $0.05 $0.12 $0.27 $1.01 $1.48 * From 7/1/09 DeGolyer & MacNaughton report & based on NYMEX price of $66.62 per barrel of oil with no escalation. Royalty interest bears excise taxes, but no operating costs. Reversionary interest bears excise taxes and direct operating costs. Total future operating cash flows = ~$21/share. 17

18 EPM Assets: Conventional Re-development Neptune Oil Project in South Texas Artificial Lift Technology Giddings Field in Central Texas 18

19 Neptune Oil Development Within Mature Field 7/1/09 Net Reserves # Locations MBO PV-10 Net Proved Reserves 4re-entries entries 48 $05MM $0.5 Net Probable Reserves $0.4 MM Net Possible Reserves (in 2P locations) 247 $7.2 MM 542 $8.1 MM 100% working interest and 79.7% net revenue interest; 1,502 net acres to date Up to 79 additional drilling locations projected from historical infill results field has produced ~32 MMBO to date from 380 wells (no current production) First 2 producers and 1 injector expected to be drilled early in FY2010 Project originated from EPM experience with a similar field in Louisiana that required infill drilling down to far less spacing to fully develop field with same rock and oil properties. 2P reserves bear all capex; 3P reserves are associated with the 2P wells. 19

20 Neptune Oil Development Within Mature Field Project based on historic downspacing in this field and similar EPM experience in comparable field in Louisiana Application of our innovative completion technology may = additional upside ~380 previous wells now P&A d ~100 new infill locations 4 PUD, 21 Pb & 79 pending area drained by well 11 infill wells drilled in 1970 s : similar to our program, made >50 MBO each on average 20

21 Proprietary Artificial Lift Technology Original fluid level Conventional artificial lift Fluid level eventually drops to a level where rod pump or gas lift are no longer effective This can leave substantial volumes of oil and gas. Our technology Mobilizes remaining fluid to the pump Fluid level l at Cost $4-10 of investment per net BOE. conventional abandonment Remaining potential Reservoir 21

22 Giddings Field, Central Texas 7/1/09 Net Proved Reserves = 3.0 MMBOE $35.3 MM PV-10 Net Probable Reserves = 0.9 MMBOE $10.9 MM PV-10 Drilling locations Ave Gross Recovery Ave D&C cost/well D&C / BOE 14 proved re-entries 111 MBOE/well $1.3 MM $ proved grassroot & 270 MBOE/well $2.3 MM $ probable grassroot 100% WI, ~80% NRI in 10 producers & ~18,000 net acres Naturally fractured Austin Chalk, Georgetown & Buda no hydraulic fracs required Wells typically produce at high initial rates (~150 BOEPD for re-entry well, ~340 BOEPD for grassroots well) followed by steep initial declines, then stabilize with about half of estimated reserves produced in first two years Reserves estimated to be 30% oil, 35% gas liquids and 35% natural gas; and 14% developed Last 2 re-entries drilled in Giddings Field yielded average 8 day rate of 450 BOEPD 22

23 Price Sensitivity of Giddings/Neptune Reserves* EPM Giddings & Nepturne (1P + 2P) PV-10 per fully diluted share vs Blended Flat Commodity Price ) $/Share (30% oil, 35% ngl & 35% natural gas) $2.00 Proved $1.80 Probable $1.60 $1.40 $1.20 $1.00 Gas price increase begins to add back locations $0.80 $0.60 $0.40 $0.20 $- Report as of 7/1/2009 $20 $25 $30 $35 $40 $45 $50 $55 $60 $/BOE NYMEX 23 * Flat prices & costs

24 EPM Assets: OK Low Cost Gas Shales Project 24

25 Gas Shales in Eastern Oklahoma ¾ Up to 100 vertical and horizontal Woodford completions to date offsetting EPM acreage by three other operators Woodford Completions Tulsa ¾ Potential for conventional oil development Main W df d Woodford Trend Oklahoma 25 EPM Acreage

26 Shallow = Low Cost Developing up to 200 BCF of shale gas potential at $ $1.25 per MCF Shallow depth = small rig and low fracturing horsepower = low day rates Multiple shale zones identified and tested to date Expect D&C costs to be ~$180K for vertical Wagoner well (multi-zone frac) at 1500 depth, $1.2 2 MM for horizontal well in Haskell at 4,000-5,000 depth 3 drilled wells and 3 re-entries tested with 1 core by EPM in Wagoner Targeting MMCF per vertical well (1,200 1,800 ) in Wagoner Targeting BCF per horizontal well (4,000 5,000 depth) in Haskell 100% WI in ~17,600 net acres, average ~80% NRI Lease terms generally extend ~3-5 years from lease date Wagoner vertical well spacing at 40 acres could be further downspaced Haskell horizontal well spacing at 80 acres Substantial additional acreage is typically obtainable through forced pooling 26

27 EPM Summary 27

28 EPM Financial Strength Strong balance sheet and excellent liquidity Substantial working capital No external funding required for conservative capital expenditure program in FY2010 We control our assets and required capital expenditures Financial Strategy: a conservative approach to optimize our asset values over the next few years without requiring external capital raising on unfavorable terms. 28

29 EPM Operational Strength for Growth EPM Intangibles Experienced Staff Successful Team Record Tight sand/horizontal expertise 6 Year Track Record Technology EPM Tangible Assets $7MM WC & no debt 13.6 MMBO Delhi EOR 4 MMBOE Giddings 0.5+ MMBO Neptune Above is 93% oil price related + 17,600 net acres shale gas FY2010 Value Catalysts Delhi producing OK confirmation Neptune producing Optimize Giddings Commercialize technology 29

30 (NYSE Alt: EPM) Company Contact: Sterling McDonald, VP & CFO (713) IR Contact: Lisa Elliott / lelliott@drg-e.com lli Jack Lascar / jlascar@drg-e.com DRG&E /

31 Exhibits Quick Facts Liquidity 2009 Events and 2010 Catalysts t Effect of Different Recoveries on EPM s Delhi Interests Illustration of Giddings Development Management team Board of Directors 31

32 Quick Facts about EPM Ticker Symbol EPM Fiscal Year-End June 30 Market Cap ~$74 million as of 8/26/2009 Enterprise Value ~$67 MM 26.5 MM shares outstanding 32.4 MM shares fully diluted ~39% owned by institutions Financial Strength $7 MM in WC, no debt Assets low risk development projects created by EPM Team Record 6 year successful record in creating and implementing 4 major projects 32

33 EPM Liquidity 3/31/09 (unaudited) Selected Assets Working Capital $7,503,457 Properties & Equipment, net 28,655,188 Other Assets (primarily long term CD) 356,399 Total Assets $37,980,788 Long Term Liabilities & Equity Long Term Debt $0 Other Liabilities (primarily deferred income tax) 4,471,156 Total Long Term Liabilities 4,471,156 Equity $32,043,888 33

34 2009 Events 2010 Catalysts Accomplishments in FY Giddings PUD s averaged initial gross 450 BOEPD per well Completion of Denbury s Delta CO 2 pipeline to Delhi Positive test results in OK low cost gas shale resource Successful first field test of artificial lift technology in Giddings Maintained liquidity and strong balance sheet with no debt Growth Catalysts for FY 2010 Continued testing of low cost shale resource in OK Commencement of drilling in Neptune So. Texas oil project Initiation of CO 2 injection at Delhi Production response from CO 2 injection at Delhi 34

35 Effect of Different Recoveries on Delhi Volumes Estimated EPM Net Probable Reserves in Delhi CO 2 -EOR Project CO2R Recovery of fswept tooip: 13% 15% 19% (at $66.62 oil, SEC pricing) Gross bbls produced (MMBO) EPM royalty interest (7.4%) Other royalty interests (12.6%) Total royalties (20%) % WI reserves (80% of RI) WI bbls produced before Payout WI bbls - remaining after Payout EPM 25% WI after Payout EPM 7.4% Royalty (from above) Total Net EPM bbls at Delhi RI = revenue interest = share of gross production WI = working interest = cost-bearing interest, earns gross production less royalties Payout = deemed payout = $200 MM of 100% WI revenues less field operating expense Royalty = revenue interest bearing no capital or operating costs Swept OOIP = original i oil in place in portion of reservoir swept by CO 2 35

36 Giddings Field Infill Development Lease boundary - mandatory distance between vertical wellbore and lease boundary lease boundary plug Naturally occuring fractures bearing oil and gas Austin Chalk New horizontal wellbore penetrating undrained fractures Existing horizontal wellbore penetrating multiple fractures that contain oil and gas 36

37 Our Management Team Robert Herlin, CEO & Chairman Co-founded EPM in 2003 and built company using $8.3 million of equity capital 27 years of leadership experience in M&A, development, operations and finance in public and private sectors $800 million in transactions completed Originated and led horizontal drilling team in early years of horizontal drilling adoption by industry B.S. and M.E. in chemical engineering (Rice University) and MBA (Harvard) Sterling McDonald, CFO CFO since 2003 Former CFO for PetroAmerican Services, PetroStar Energy and Treasurer for Reading & Bates Corporation Responsible for raising ~$4 billion in capital B.S. and MBA (University of Tulsa) 37

38 Our Management Team Daryl Mazzanti, VP-Operations Joined team in mid-2005; 21 years of experience in oil & gas industry Former Manager of US Business Development for Anadarko Former Production Manager, Austin Chalk for Anadarko/UPRC responsible for 1200 wells, staff of 65 and 25,000 BOEPD of production Responsible for numerous innovations in horizontal drilling, completions and artificial i lift B.S. in Petroleum Engineering (University of Oklahoma) Edward Schell, General Manager for Drilling and Unconventional Development Joined team in late 2006; 25 years of experience in oil and gas industry Various management positions in drilling, operations and business development at Anadarko Petroleum Particular expertise in horizontal drilling and tight gas reservoirs Drilled ~800 wells, 200 being horizontal and 2/3rds being in unconventional reservoirs B.S. in Petroleum Engineering (University of Texas) 38

39 Our Board of Directors Robert Herlin, CEO, Chairman & Co-founder Laird Cagan, Director & Co-founder Managing Director Cagan McAfee Capital Partners Formerly with Goldman Sachs and Drexel Burnham Lambert E.J. DiPaolo, Director Energy Partner with Growth Capital Partners, L.P. Former Halliburton Group Senior Vice President of Global Business Development Gene Stoever, Director Retired Partner with KPMG Peat Marwick Former SEC Reviewing Partner for KPMG CPA in the State of Texas and member of the AICPA Bill Dozier, Director Former SVP-Business Development for Vintage Petroleum Former SVP-Operations for Vintage Petroleum Formerly in operations for Santa Fe Minerals and Amoco Kelly W. Loyd, Director Director with JVL Advisors, LLC, a private energy investment company Formerly Associate with RBC Capital markets Formerly Founder of L.A.B. sports and Entertainment and Managing Partner of Tigre Leasing, LLP 39