Corporate Presentation. 1Q08 Conference Call The date of these presentation materials is May 5, 2008

Transcription

1 Corporate Presentation 1Q08 Conference Call The date of these presentation materials is May 5, 2008

2 Certain Reserve Information The Securities and Exchange Commission has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms probable and possible reserves, reserve potential or upside or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. Forward Looking Statements This presentation includes certain statements that may be deemed to be 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, as amended. 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. They include statements regarding the company s financing plans and objectives, drilling plans and objectives, related exploration and development costs, number and location of planned wells, reserve estimates and values, statements regarding the quality of the company s properties and potential reserve and production levels. These statements are based on certain assumptions and analysis made by the company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes appropriate in the circumstances, including the assumption that there will be no material change in the operating environment for the company s properties. Such statements are subject to a number of risks, including but not limited to commodity price risks, drilling and production risks, risks relating to the company s ability to obtain financing for its planned activities, risks related to weather and unforeseen events, governmental regulatory risks and other risks, many of which are beyond the control of the company. Reference is made to the company s reports filed with the Securities and Exchange Commission for a more detailed disclosure of the risks. For all these reasons, actual results or developments may differ materially from those projected in the forward-looking statements. Drilling Schedule Statement The drilling schedules in this presentation have been prepared based on our current understanding of PVA s current plans as well as our own and is subject to change based on numerous factors, including changes in PVA plans, drilling results, equipment availability, weather conditions and other factors. It also assumes that GMX has financial capacity in sufficient amounts to pay its share ofcosts. Accordingly, there is no assurance that the drilling schedule will occur as projected. GMX does not plan to commit to drilling of any well unless favorable conditions exist and it has the resources available for payment of costs. Research Reports Information referenced from research reports has been prepared by independent third parties and not the Company. By including this information, the Company does not endorse or adopt the information and does not accept responsibility for its accuracy or completeness. 2

3 Company Overview Texas Louisiana CHK Hz. Well Symbols Gas Well Started Well Horizontal Well GMXR Acreage 34,000 gross / 21,000 net Map as of May 5,

4 GMXR Strategy Build Shareholder Value Accelerate Developed Asset 1P 2P 3P Monetize Probable Exploit Upside Potential Drill Undeveloped Locations Faster 36% % Maintain Low F&D Cost $.79/Mcfe 100% Success to Date 20 Acre In Fill 2/3 20 Acre 1/3 40 Acre Substantial Undeveloped Opportunity 600+ locations High Probability for Drilling Success Deeper Layers Haynesville Horizontal Drilling Add Shallow Zone Oil Opportunities Add Acreage in & around core Remain Operationally Efficient Industry Lowest F&D Cost Finance Prudently, Cash Flow & Bank Debt. Use Equity Only When Accretive GMXR Value Proposition $2.00 $56 / Share 15,560,000 shares $ $42 / Share + 16,400,000 shares $.50 $25 / Share 16,600,000 shares $2,000 $1,800 $1,600 $1,400 $1,200 $1,000 $800 $600 $400 5 Year Cumulative Total Return * Record Equity Return * $100 invested on 12/31/02 in stock. Fiscal year ending December 31. $200 $

5 Established Reserve Base Provides Strong Production Growth Bcfe 2,000 1,800 1,600 1,400 1,200 1, Bcfe PUD PD 64 Bcfe PUD PD Total Reserve Growth (2) 704 Bcfe 3P 2P PUD PD 955 Bcfe PUD PUD PUD /1/2008 3P 2P PD 1,384 Bcfe 3P 2P PD 1,975 Bcfe 3P 2P PD Haynesville 800 BCFE Includes 20 Acre CV spacing Growth Not Yet Estimated Plus 68 Bcfe 2008 Possible Reserves include 800 Bcfe Haynesville/Bossier 20-acre successes represent strong upside near-term potential PUD reserves represent low-risk source of immediate growth 36% of reserves and 53% of PV-10 value proved developed Mar- 04 Annual Production Growth (Bcfe) 1-4 Rigs 0 Rigs 0-2 Rigs Rigs Rigs Jun- 04 Doubled Annual Production for 3 Years Sep- 04 New Guidance! Production Growth Profile (MMcfe/d) Increased Guidance! Dec- Mar- Jun- Sep Dec- Mar- Jun- Sep Dec- Mar- Jun- Sep Quarters of Production Growth 8-9 Rigs Dec- Mar- Jun (2) (1) 3P = Possible; 2P = Probable; PUD = Proved Undeveloped; PD = Proved Developed (2) As per company guidance. 5

6 Cotton Valley Fields Haynesville / Bossier Gas Shale TEXAS Emerging Play in East Texas / N. LA LOUISIANA GMXR Haynesville / Bossier 6.6 TCFE Net Gas-in-Place Camterra Horizontal Wells Chesapeake Horizontal Wells Encana Wells Haynesville Well Symbols CVS Gas Well Haynesville / Bossier / Smackover Producing Wells Map as of April 24, 2008 Texas 51 Haynesville/Bossier Wells in Harrison & Panola Counties; TD >= 11,000 Horizontal Louisiana 16 Haynesville/Bossier Wells Haynesville / Bossier Horizontal Hz Potential Wells GMXR Acreage 34,000 gross / 21,000 net 6

7 Geologic Overview Open Hole Gamma Ray Gas Shows Multiple Targets: GMXR assets contain multiple formations to be exploited Orange Silt Gas Shows Pettit Travis Peak / Hosston Sands Conventional Reservoirs GMXR has 2.3 Tcfe in place on its 21,000 net acres in Cotton Valley GMXR has 6.6 Tcfe in place on its 21,000 net acres in Haynesville/Bossier Gas Shale Yellow Sand or Lime Purple Gas Shale 350 Haynesville Pay! Gas Shows Gas Shows Gas Shows Gas Shows Middle TP Sands Cotton Valley Sands Haynesville /Bossier Smackover UCV LCV Estimated Gas-in-Place Per 40 Acres 2.1 BCFE 0.5 BCFE 1.7 BCFE Estimated Gas-in-Place Per 120 Acres 38 BCFE Weighted average 1.27 Bcfe Cotton Valley EUR / well on 40-acre spacing equates to 30% recovery vs. 70% - 80% industry target Gas Shales Tight Limes (1) Company internal estimates of gas in place. 7

8 Best-in-Class Operational Performance Lowest Cost Producer $ / MCFE UPL GMX EQT KWK CXG WMB EGN XTO RRC STR APA EOG CRZO MDU COG OXY SD DVN WLL PXD GDP SWN PVA NBL DNR GSX PXP SM PLLL BGG CHK XEC UNT NFX FST APC CRK EP ME ATPG PAQ SFY MUR CPE MMR SGY BEXP All Sources F&D Cost 5 Year Avg. GMXR 2nd Best 5 Yr. Avg. $ / MCFE $- $1 $2 $3 $4 $5 $6 $7 $8 $9 $10 $11 $12 GMXR EQT UPL GSX KWK CRZO GDP CPE RRC BGG WMB STR SD XTO PVA COG EOG DVN SGY NBL APC SWN PXD CRK APA DNR CXG EGN FST PXP NFX CHK OXY XEC UNT MDU SM ME EP BEXP PAQ MMR SFY WLL MUR ATPG PLLL All Sources F&D Cost 2007 MCFE GMXR # Nearly 100% of every $ Used to Organically Grow Production and Reserves GMX WMB EQT GDP STR ATPG CXG EOG DNR COG SWN PVA MUR MDU UNT NFX GSX EGN SM NFG APA UPL DVN CRK BEXP SFY RRC OXY WLL EP XTO XEC CPE KWK PXD NBL SGY CHK PLLL EPL PQ WTI ME BBG FST APC CRZO SD MMR PXP % of Total Cost Incurred for O&G Dev. GMXR #1 5 Yr. Avg. GMX WMB EQT GDP WLL ST R COG EGN SGY DVN DNR AT PG UNT MDU EOG APC PVA NFG RRC OXY NBL CXG MUR XBC SM WTI NFX ME CRK APA SWN BEXP PXD CHK SFY UPL PLLL SD XT O EPL BBG PQ KWK EP CPE FST CRZO PXP MMR GSX % of Total Cost Incurred for O&G Dev. GMXR # % 20% 40% 60% 80% 100% 0% 20% 40% 60% 80% 100% 8

9 Best-in-Class Operational Performance Multiple Layers of Quality Reservoirs Cause Repeatable Successful Development Drilling Full Cycle Economics Industry Leading GMXR SD GSX UPL GDP PXP CRZO KWK RRC CHK MMR XTO WLL PVA PLLL SWN ATPG ME BBG XEC EQT NBL PXD APC FST CXG SM DNR NFX WMB APA STR COG EOG UNT EGN CRK PQ DVN OXY BEXP MDU WTI SFY EP CPE MUR EPL SGY NFG UPL GMXR XTO CXG OXY RRC APA EQT SWN PVA EOG CRZO WLL KWK CHK COG XBC SM DNR NBL EGN DVN NFX UNT STR PXD MDU GDP BBG ME PLLL CRK PXP WMB SFY PQ ATPG FST MUR WTI APC CPE SGY BEXP MMR \SD EPL NFG EP GSX Reserve Replacement 5 Year Avg. 0% 500% 1000% 1500% 2000% GMXR #1 5 Yr. Avg. Full Cycle Economics GMXR #2 5 Year Avg. -100% 0% 100% 200% 300% 400% 500% GMX EQT PXP GSX UPL PXD SD CXG GDP KWK CRZ RRC COG EGN WLL XTO PVA PLLL CHK CPE OXY FST STR SWN SFY WMB EOG DNR NBL CRK APA APC ATP DVN NFG SM NFX UNT EP BEXP MDU BBG XBC MUR ME MMR EPL WTI SGY PQ Year-End Reserves to Production Ratio GMXR # Years Source: Howard Weil 2007 Reserve and Finding Cost Study Definitions All Sources = Total Cost Incurred / Total Reserve Additions Drilling = Land Acquisition Costs + Explorations + Development / Drilling Reserve Additions Drilling & Revision = Land Acquisition Costs + Exploration + Development / (Drilling Reserve Additions + Revisions to Reserves) Acquisitions = Reserve Acquisition Costs / Reserve Acquisition Additions Full Cycle Economics = Cash Flow / All-Sources Finding Cost 9

10 Operating and Financial Data vs. Peers (1) Reserve Growth vs. Peers Production Growth vs. Peers 80% 74% 72% 2007 Production Growth 120% 100% 80% 60% 40% 20% 0% 102% 61% 49% 46% 44% GMXR SWN CRZO HK GDP UPL CRK FST DPTR PLLL Production Growth over 100% Last Three Years 32% 30% 28% Median = 38% Reserves Represent Low Risk Near Term Source of Cash Flow Efficient Operations Drive Low Overall Costs 19% 3% 2007 Proved Reserve Growth 2007 Cash OPEX + DD&A ($ per Mcfe) 70% 60% 50% 40% 30% 20% 10% 0% -10% $18.00 $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- 66% 46% 41% 27% 25% 24% Median = 34% GDP GMXR CRZO FST SWN CRK UPL DPTR PLLL HK $10.83 $5.77 $5.40 $3.67 $3.40 Total Operating Costs vs. Peers $4.99 $2.55 $2.42 $2.19 $2.84 $2.49 $2.69 $2.55 $1.97 $2.14 $2.34 Median = $4.90 $1.24 $0.27 $1.26 $1.37 DPTR CRK GDP HK CRZO PLLL FST GMXR UPL SWN 8% -1% Cash Operating Costs DD&A Expense (1) Data obtained from companies K. 10

11 Operating and Financial Data vs. Peers, Reserve Growth (1) EV per MCFE/d slightly above median Proved Reserves Per/Sh Highest Among Peers! EV per MCFE Proved Reserve Lowest Among Peers Total Reserves Per/Sh Highest Among Peers! TEV per 2007 Proved Reserve ($ per Mcfe) TEV per 2007 Daily Production ($K per Mcfe/d) $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 EV per MCFE/D vs. Peers (2) $39.87 $38.77 $36.11 $29.05 $26.61 $26.44 $21.67 $15.66 $15.04 $10.61 CRZO DPTR UPL GDP GMXR PLLL SWN HK FST CRK EV per MCFE Proved Reserves vs. Peers (2) $5.50 $5.03 Median $4.71 $4.65 $4.37 $4.03 $3.77 $3.02 Median = $26.53 Median = $4.20 $2.42 $1.46 CRZO DPTR HK SWN PLLL UPL GDP FST CRK GMXR MMCFE for 2007 Proves Reserves per Share MMCFE for 2007 Total Reserves per Share MCFE Proved Reserves per Share vs. Peers (1) Median = 11 PLLL DPTR HK SWN GDP CRZO UPL CRK FST GMXR MCFE Total Reserves per Share vs. Peers (1) Median = 60 CRK* PLLL* SWN HK GDP UPL DPTR CRZO FST GMXR *3P Information was not available (1) Data obtained from companies K and company presentations. (2) For GMXR EV = current market cap as of 4/1/08 excluding 3.24 million shares issued under a share lending agreement + (preferred stock + debt - cash as of 12/31/07). Current market cap of peer group is based on stock prices as of April 1,

12 Build Shareholder Value Financial Strategy Flexibility in capital program allows Company to quickly adjust to market conditions. Achieve financial stability with prudent leveraging and hedging. Minimize our execution risk by taking a manufacturing approach to monetizing our resource base maximize profits by focusing on cost control. Aggressively grow production and cash flow through well-managed capital program with highly predictable results utilizing a flexible rig program Capital program designed to take advantage of current market conditions and best-in-class finding and development costs Maintain prudent leverage with targeted long-term debt/capitalization ratio of 50% or less Continue to engage in hedging of producing reserves to allow development execution and reduce the impact of commodity price fluctuations Use owned rigs and operated rigs as throttle for capex to continue reinvesting in our extensive resource base and acquire additional operated assets in or near our core operating area 12

13 1Q08 Financial Results Record oil & gas production 2.87 BCFE Up 60% from 1.79 BCFE in the 1Q07 Higher: Production and Revenues Record oil & gas sales amount $27.2 million Up 106% from $13.2 million in 1Q07 General & administrative expenses $.90 MCFE Down 10% from $.99 MCFE in the 1Q07 Lower Costs per Unit: G&A Record Non-GAAP DCF of $17.9 million Up 92% from $9.3 million in 1Q07 Diluted earnings per share $.40 Record Non-Gaap Cash Flow (1) = Excellent Qtr. Up 90% from $.21 in the 1Q07 (1) Cash flow from operations before changes in working capital 13

14 ($Millions) Financial Summary Oil & Gas Revenue ($MM) Discretionary Cash Flow ($MM) (1) Consistent drilling results provide dramatic production, revenue and cash flow growth $140.0 $120.0 $100.0 $80.0 $60.0 Increased Guidance! $67.9 $125 (3) $90.0 $80.0 $70.0 $60.0 $50.0 $40.0 Increased Guidance! $40.8 $80.0 $40.0 $20.0 $19.0 $31.9 $30.0 $20.0 $10.0 $12.5 $19.3 $60MM Infrastructure in place; 2008 Capex is 10% less than 2007, yet GMXR will drill 12% more wells. $0.0 $200.0 $150.0 $100.0 $50.0 $0.0 $ e Capex ($MM) / Gross Wells Drilled Increased Guidance! $39.5 $130.6 $197.0 $ e (2) $ e Daily Production Exit Rate (MMcfe/d) 9.2 Increased Guidance! Q05 4Q06 4Q07 4Q08e CAPEX Gross Wells Drilled (1) Calculated as EBITDA less net interest expense, taxes and preferred dividends plus stock based compensation. (2) Previous guidance of $175 million adjusted upward to $195 million related to current cash flow and natural gas price environment. (3) Estimate is projected revenues and based on current national gas price environment. 14

15 Consistent historical growth with increasing EBITDA margins Strong credit profile and significant collateral coverage through: Proved Reserve Value $8.06 HH = PV-10 $797MM ($Millions) Financial Summary Operations Year ended 31, December Profile e Daily Production (mmcfe/d) Revenues Oil & Gas Revenues $7.7 $19.0 $31.9 $67.9 $125.0 Expences LOE Production Taxes G&A (2) EBITDA $3.9 $12.3 $21.8 $49.1 $95.0 % Margin 51.0% 64.8% 68.3% 72.3% Capex $8.9 $39.5 $130.6 $197.5 $195.0 Credit Actual As Profile Dec. 31, 2007 Adjusted (1) Total Debt $125.7 $156.7 Total Interest Expense 4.1 NA SEC PV-10 $592.8 $592.8 Proved Reserves (Bcfe) Proved Developed Reserves (Bcfe) Key Credit Metrics Total Debt / EBITDA 2.6x 3.2x EBITDA / Interest Expense 12.0x NA PV-10 / Total Debt 4.7x 3.8x Debt / Proved Reserves $0.29 $0.36 Debt / Proved Developed Reserves (1) Adjusted as of December 31, Reflects the recent $125 million convertible senior note transaction in February The Company s outstanding balance under its bank line of credit was paid in full from these proceeds. Company expects to re-borrow under the bank line of credit. (2) Excludes Stock Based Compensation (SBC) 15

16 Balance Sheet Strength ($Millions) Year-end pro forma debt to capital percentage of 41% Payable in Cash Non-Convertible As of 2006 YE 2007 YE March 31, 2008 Cash and Cash Equivalents $5.0 $5.9 $3.7 Long-Term Debt (1) Bank Credit Facility (5%) $40.0 $94.0 $14.0 Series A Secured Notes (7.58%) Net Share Convertible Security (5%) JV Project Financing Total Series B Preferred Equity (9.25%) Common Equity Total Capitalization $178.3 $340.7 $379.9 Debt to Capital % 23% 37% 45% (1) Includes current portion of long-term debt. 16

17 2008 Capital Program ($Millions) Source of Funds Use of Funds (1) Convertible Senior Notes & Bank LOC (2) $125.0 Drill 132 gross / 84 net $ e Cash Flow 65.0 Acreage, infrastructure & other working cap 27.0 Total Sources $190.0 $ E cash flow represents mid-point of estimated cash flow range Benefits of Issuing Convertible Notes with a Net Share Settlement $125 million is paid in cash at conversion or maturity (2013) Until the conversion price of $32.50 is exceeded, no incremental shares are added to fully diluted share count Low interest rate of 5% and accretive to cash flow Common shares issued under the share lending agreement are required to be returned to Company at conversion or maturity. We will not include loaned shares in calculation of earnings per share. The number of shares issuable upon conversion may be increased in connection with certain extraordinary corporate events, such as a change in control Potential dilution at future stock prices Stock Price Potential Shares to be issued at maturity or conversion (3) $35 274,725 shares $40 721,154 shares $50 1,346,154 shares $60 1,762,821 shares $80 2,283,654 shares $100 2,596,154 shares $120 2,804,487 shares (1) Assumes mid-point of projected capital budget, current gas price environment, operating costs and drilling cost. (2) The proceeds from the convertible senior notes were used to fully repay the bank line of credit (LOC) which as of 10/1/07 has a borrowing base of $90 million; the Company expects a bank line of credit increase to $150 MM - $180 MM in The Company will draw on the bank line of credit to fund the 2008 capital program. (3) Company has the option to pay the value in excess of the conversion price in shares or cash. 17

18 Key Investment Highlights High Quality Reserve Base with Attractive Acreage Position Proved reserves of approximately Bcfe with significant upside potential 72% increase in proved reserves since 12/31/06 94% natural gas and 36% proved developed (up from 30% 2006) Average Cotton Valley EUR of 1.27 Bcfe and avg. Pettit / Travis Peak EUR of 0.64 Bcfe per well Over 34,000 gross (21,000 net) contiguous acres in East Texas (up 25% from 2006) (3) East Texas Cotton Valley is mature, well-understood gas play with extensive infrastructure Operate 65% of Cotton Valley acreage (up from 60%, 2006) and can cause non-opr. drilling locations Total Reserve 1,975 BCFE Significant Sustainable Cash Flow Extensive Cotton Valley Sand, Pettit / Travis Peak & Haynesville / Bossier Shale Drilling Inventory Current production of 32.3 MMcfe/d (4) 335 gross / 196 net producing wells (5) Low production risk across all producing assets with 100% success rate High IRR and ROI on new drills Expect current capitalization to bridge through 2010 (2) Large inventory of repeatable drilling opportunities In excess of 437 gross (296 net) CVS proved drilling and workover opportunities provide low-risk incremental near-term cash flow; plus 1,032 gross / 615 net probable/possible drilling locations Infill drilling gaining momentum as 20-acre spacing continues to display strong economics 175 Haynesville / Bossier Shale Horizontal 120 Acre Locations 2008 capital expenditure budget of $195 million gross / net wells Attractive Valuation & Economics NAV per share of $40.00 based on proved PV-10 of $797MM (1) High relative realized price for produced gas due to favorable processing agreements and infrastructure investment Best in class F&D, full cycle cost structure 2007 EBITDA of $47.7 million (125% increase over 2006) (1) Current proved PV-10 with HH cash price 2/11//08 $8.06 / mmbtu and $93.44 / Bbl oil. NAV per share includes current debt; 14.8 MM shares. (2) Based on projected cash flow & current commodity prices and expected bank borrowing and projected capex. (3) Includes pooled interests. (4) Average 7 day production for week ending 3/22/08. (4) As of May 5,

19 Infrastructure Assets 19

20 Endeavor Pipeline Co. Endeavor Pipeline, compression & Saltwater disposal wells Wholly-owned subsidiary Take away capacity Endeavor Pipeline Co., a wholly owned subsidiary of GMXR, has a book value of $20MM based on Company costs 62 MMcf/d current; 67 MMcf/d by 3Q08 Current: 100% area production 19.3 MMcfg/d & 21.3 MMBtu/d PVA 60 MMcf/d; 80 MMcf/d by 4/08; Current: JD area production 45.7 MMcfg/d & 53.7 MMBtu/d Currently 135 miles of pipelines & 32 miles of ROW in 100% Area; high & low pressure, gas lift gas & disposal lines Fixed JD fees Saltwater disposal $0.50 / Bbl & gathering $0.10 / Mcf cost 20

21 $60 MM Infrastructure Carthage North Field Field Office, Rig Yard & Marshall, TX Land Office Diamond Blue Drilling Company, a wholly owned subsidiary of GMXR, has a book value of $30MM based on Company costs Field office book value of $10MM Operator Rigs Contract Depth Drawworks Add Term Horsepower Top Drives GMXR DBD #9 GMXR Owned 15,000' 1,200 4/16/08 GMXR DBD #11 GMXR Owned 14,000' 1,000 5/5/08 GMXR DBD #7 GMXR Owned 11,000' 1,000 4/26/08 GMXR Unit #309 Well by Well 12,500' 1,000 3/2/08 GMXR Unit #324 Pending 18,000' 1,500 PVA H&P Flex # day renewable PVA GW Flex #102 Through 2009 PVA H&P Flex #185 3 well renewable PVA H&P #156 Well to Well Carthage North Field Office Employee Consultant 3rd Party Drilling Completion Production / PL Total All Fields Field Office 12, 000 sq. ft. & 40 Acres Yard 166 Acres Owned Frac Water Filter Storage Tanks (15) 640 Bbls each SWD Well(s) 2 Compression 10,500 HP 21

22 Build Shareholder Value Summary Highlights Year end 2007 Proved PV-10 of $593 MM; 2/11/08 $797 MM Strong proved reserve base Proved reserves Bcfe as of 12/31/08 Total reserve potential of 2 Tcfe as of 4/1/08 High profitability Outstanding historical and projected growth profile Contiguous acreage block with large infrastructure investment of $60MM $0.79 / Mcfe All Sources Finding & Development cost per unit (5 yr. avg.) Fifty 20 acre producers by Dec % production growth 2007 over 2006 Management owns 22% of fully diluted common equity 2.3 Tcfe gas-in-place in the Cotton Valley 175 Haynesville / Bossier Gas Shale Horizontal 120 Acre Locations 6.6 Tcfe gas-in-place in Haynesville / Bossier Gas Shale 22

23 Appendix 23

24 Proven Management Team years of oil & gas experience Management owns 22 of fully diluted common equity Ken Kenworthy, Jr. - President & CEO, Chairman of Board James Merrill CFO, Secretary & Treasurer, CPA Michael Rohleder Vice President Corporate Development & Investor Relations Richard Hart, Jr. - Vice President, Operations, P.E. Gary Jackson Vice President, Land Keith Leffel President, Endeavor Pipeline Charles Pope - Drilling & Completions Manager, P.E. Timothy Benton Acquisitions & Divestiture Manager, P.E. 24

25 Hedges (1) 49% of current production hedged All gas hedges are HSC (Houston Ship Channel) Natural Gas (MMBtu / month) Oil / (Bbls / month) Volume Price Term 200,000 $ $7.50 Jan-09 to Dec ,000 $ $7.50 Jan-10 to Dec ,000 $ $7.50 Jan-08 to Dec ,000 $7.46 To Dec ,000 $7.60 Aug-07 to Dec ,000 $ $12.20 Jun-08 to Dec-09 5,000 $70.00 Sep-07 to Dec-08 5,000 $ $ Jan-09 to Dec-09 (1) As of May 5,

26 Cotton Valley Economics & Development Plan CV Gross Production Type Curve (Mcfe/d) Travis Peak Economics and Development Plan TP Gross Production Type Curve (Mcfe/d) Avg. Daily Rate (mcf/d) Avg. Daily Rate (mcf/d) Average Gross PUD Well ($'000s) IP Rate (Mcfe/d - month one avg) 773 Estimated EUR (Bcfe) Estimated Well Cost $2,000 Cumulative Undisc CF (1) $5,039 PV-10 (1) $1,573 Months Single Well Return Sensitivity (Gross) Price Deck IRR ROI $ % 4.0x $ % 3.4x $ % 3.1x $ % 2.9x $ % 2.6x Average Gross PUD Well ($'000s) IP Rate (Mcfe/d - month one avg) 286 Estimated EUR (Bcfe) 0.64 Estimated Well Cost $890 Cumulative Undisc CF (1) $3,034 PV-10 (1) $1,483 Months Single Well Return Sensitivity (Gross) Price Deck IRR ROI $ % 4.9x $ % 4.3x $ % 4.0x $ % 3.7x $ % 3.3x 2008 Drilling program includes the following schedule (2) : 100% WI Area (GMXR Operated): net wells 50% WI Area 40 gross / 20 net wells 30% WI Area: 36 gross / 11 net wells 2008 Drilling program includes the following schedule (2) : 100% WI Area (GMXR Operated): 5 gross / net wells 50% WI Area 3 gross / 1.5 net wells 30% WI Area: 2 gross / 0.6 net wells Single-well economics for average Cotton Valley PUD well Total of 118 gross / 73 net wells to be drilled in 2008 Single-well economics for average Travis Peak PUD well Total of 10 gross / 7.1 net wells to be drilled in 2008 (1) Based on NYMEX strip pricing average $8.23 as of 1/25/08. Net of well cost. (2) Company internal estimates; Schedule dependant upon rig efficiency. Number of wells to be drilled in all areas are estimated. Net ownership of wells will increase by leasing & unitization. Wells assume 30 days spud to spud for vertical conventional rigs UCV; 15 days spud to spud for flex rigs, updated 12/19/07. 50% & 30% WI Areas are Joint Development Operations. 26

27 Analyst Contacts Company Analyst Name Telephone CapitalOne Southcoast, Inc. Richard Tullis Ferris, Baker Watts, Inc. Richard Rossi Kim Pacanovsky, Ph.D Howard Weil, Inc. Jonathan Robert Peter Kissel Jefferies & Company, Inc. Biju Perincheril Morgan Keegan & Company, Inc. Chris Pikul, CFA James Babka Pritchard Capital Partners, LLC Stephen F. Berman, CFA Sidoti & Company, LLC Mark Lear, CFA Tudor Pickering Holt & Co. David Heikkinen

28 Glossary of Terms 1P Proved Reserves MBbls One thousand barrels of oil 2P Probable Reserves M CF One thousand cubic feet of gas 3P Possible Reserves M CFE One thousand cubic feet of gas equivalent bbl or bo barrel of oil mcfepd One thousand cubic feet of gas equivalent per day BCFE Billion Cubic Feet Gas Equivalent (oil & gas combined 6:1 M M CF One million cubic feet of gas basis to gas equivalent) CAPEX Capital Expenitures M M CFE / d One million cubic feet of gas equivalent per day CCV Completed Cotton Valley mmcfg Million cubic feet gas CVS Cotton Valley Sand Well mmcfgpd M illion cubic feet gas per day CWC Completed Well Cost PE Petroleum Engineer E&P Exploration and Production Poss Possible Undeveloped Wells Estimated Estimated future gross revenue to be generated from the Present Value Discounted cash flow or revenue to today's dollars Future Net production of proved reserves, net of estimated production, Prob Probable Undeveloped Wells Revenues future development costs, and future abandonment costs, PUD Proved Undeveloped Wells using prices and costs in effect as of the date of the report or PVA Penn Virginia Corporation estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt PVOG Penn Virginia Oil and Gas service and future income tax expense or to deprecation, Reserve Calculated by dividing reserve replacement by production depletion and amortization. Replacement in the same period. Reserve replacement is calculated by EUR Estimated Ultimate Recovery Ratio summing the total reserves added over a particular period. F&D Finding and Development Costs. Calculated by dividing the Spud To begin drilling operations on a well sum of costs incurred for exploration and development Takeaway The ability to move gas to a market for sale activities by total proved reserve additions. Capacity Finding Cost Sum of Expl &Dev Costs / Total Proved Reserve Additions TP/P Travis Peak / Pettit JD Joint Development TCFE Trillion cubic Feet Gas Equivalent (oil & gas combined 6:1 LCV Lower Cotton Valley basis to gas equivalent 100% Success Cotton Valley well has been drilled successfully to Total Depth (inc. side track & sub wells). Casing has been set, fracture stimulation will be or has been done. UCV Upper Cotton Valley 28

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