IPAA OGIS NEW YORK IPAA OGIS NEW YORK April 11, 2011
Forward Looking Statements This presentation contains forward looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Except for statements of historical facts, all statements included in the document, including those preceded by, followed by or that otherwise include the words believe, expects, anticipates, intends, estimates, projects, target, goal, plans, objective, should orsimilarexpressionsor variations on such words are forward looking statements. These forward looking statements are subject to certain risks, ik trends and uncertainties i that could cause actual results to differ materially ill from those projected. Among those risks, trends and uncertainties are volatility of future natural gas prices, which have been depressed recently, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties titi involved in estimating quantities of proved natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business. In particular, careful consideration shouldbegiventocautionarystatementsmadeinthevariousreportsthecompanyhasfiledwiththe SEC. GeoMet undertakes no duty to update or revise these forward looking statements. 2
Successful Turnaround in 2010 Game changing events in credit markets Collapse of natural gas prices Major, costly, time consuming litigation Failure of Gurnee Field to meet performance expectations ti 3
Turnaround Tactics Focused efforts on core opportunities to create value within constrained capital availability Realigned cost structure to profit in new gas price environment Settled litigation on favorable terms Raised new preferred equity to reduce indebtedness, provide capital for growth and facilitate extension of bank credit agreement 4
Value Creation Drivers Industry leading expertise in coalbed methane and shallow gas Significant proved reserves and additional unproved resource base Long lived reserves, shallow decline production characteristics Low risk, multi year production growth 5
CBM/Shallow Gas Experts Developer and operator of coalbed methane properties since 1985 Technical staff has developed 5 large scale CBM projects in four separate basins (Black Warrior, Raton, Central Appalachia and Cahaba Basins) Technical, professional and project management team averages more than 19 years of CBM experience Skilled in low pressure shallow gas operations Operation of low pressure gathering systems Pumping, collection, treatment and disposal of produced water Efficientoperation of compression to maintain low wellhead pressure Focus on cost control 6
Significant Reserve / Resource Base SEC Proved reserves of 216 Bf Bcf at 12 31 10 10 (229 Bf Bcf using sensitivity pricing*) ii 100% Operated 76% Developed Non proved reserves and unrisked resource of an additional ~ 650 Bcf Approximately 122,000 net undeveloped acres at 12/31/10; significant additional open acreage for follow on success 1000 Proved Probable Unrisked Resource 900 800 700 Bcf 600 500 400 300 200 100 0 570 81 216 216 * Sensitivity pricing based on NYMEX natural gas forward curve adjusted for the Company s current hedge position and historical location differentials. NYMEX prices utilized averaged $5.31 per Mcf for the first 5 years, $6.26 per Mcf for the second 5 years and $6.66 per Mcf thereafter. 7
Long lived Reserves, Shallow Decline Rates Current net gas sales volumes of 21 MMcf/day R/P ratio of 28 years Projected annual decline rate of <4% Pond Creek Field Gurnee Field 1000 1000 100 100 1 Mcf/Well/Day Mcf/Well/Day 10 10 1 1 1 1 1 1 1 1 1 10 10 10 10 10 1/1/2003 4/1/2003 7/1/2003 0/1/2003 1/1/2004 4/1/2004 7/1/2004 0/1/2004 1/1/2005 4/1/2005 7/1/2005 0/1/2005 1/1/2006 4/1/2006 7/1/2006 0/1/2006 1/1/2007 4/1/2007 7/1/2007 0/1/2007 1/1/2008 4/1/2008 7/1/2008 0/1/2008 1/1/2009 4/1/2009 7/1/2009 0/1/2009 1/1/2010 4/1/2010 7/1/2010 0/1/2010 1/1/2011 1/1/2004 4/1/2004 7/1/2004 0/1/2004 1/1/2005 4/1/2005 7/1/2005 0/1/2005 1/1/2006 4/1/2006 7/1/2006 0/1/2006 1/1/2007 4/1/2007 7/1/2007 0/1/2007 1/1/2008 4/1/2008 7/1/2008 0/1/2008 1/1/2009 4/1/2009 7/1/2009 10/1/2009 1/1/2010 4/1/2010 7/1/2010 10/1/2010 1/1/2011 2001 2002 2003 2004 2005 2006 2007 2008 2010 2003 2004 2005 2006 2007 2008 8
Low Risk Multiyear Production Growth Litigation settlement provided access to approximately 80 drilling locations in Virginia portion of Pond Creek Field 20 new locations drilled in 2010, with similar plans for annual drilling programs thereafter through 2013 Wells drilled in 2010 currently producing at average production rates above current field wideaverageand d d expected to incline to peak rates significantly higher Virginia development alone projected to yield modest production growth over four or more years while spending 1/3 to 2/3 of projected operating cash flow (dependent on gas price) 9
High Potential Growth Opportunity Gurnee Field New frac technique has yielded encouraging results when applied to previously unfraced, shallow, behind pipe zones. Involves fracing rock strata t surrounding coal (rather than the coal itself) using a shale like frac technique Results from shallow coal seams in six existing wells are encouraging, yielding incremental new production of approximately 300 Mcf per day Application of new frac technique on three newly drilled, full wellbores is in process Up to three additional full wellbore tests in 2011 Approximately 750 BCF of estimated gas in place (high confidence) 10
History of Growth Annual Sales Volumes (Bcf) Adjusted EBITDA (in 000 s) 8.000 7.000 6.000 5.000 4.000 3.000 2.000 1.000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 $45,000 $40,000 $35,000 $30,000 $25,000 $20,000 $15,000 $10,000 $5,000 $ 325.6 350.2 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 $15,000 $13,000 Adjusted Net Income (in 000 s) 209.8 400 350 Proved Reserves (Bcf) $11,000 300 $9,000 250 $7,000 $5,000 $3,000 $1,000 $1,000 $3,000 103.9 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 200 150 100 50 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 20 Bcf Proved Reserves at 12/31/2000 Approximately 400% Production Replacement 11
Areas of Operation Gurnee (Alabama) Pond Creek (Virginia & West Virginia) Lasher (West Virginia) Garden City (Alabama) Houston, Texas (Corporate Headquarters) Birmingham, Alabama (Technical Headquarters) Production and Development Area 12
Pond Creek Field Operator GeoMet 100% WI 30,000 net acres at 12/31/10 (56% developed) West Virginia ~ 475 MMcf average net EUR / well W Vi i i Virginia Average cost per well ~ $500,000 (fully allocated) Proved reserves at 12/31/10 (Sensitivity Case*): 135 Bcf Proved (73% developed) Over 15.0 MMcf/day current net gas sales West Virginia 2011 Plan: Drill up to 20 wells in Virginia Dickinson Capex: $8.8 million Equitable Nora Resources Field OakwoodCNX Gas Field Virginia *Sensitivity pricing based on NYMEX natural gas forward curve adjusted for the Company s current hedge position and historical location differentials. NYMEX prices utilized averaged $5.31 per Mcf for the first 5 years, $6.26 per Mcf for the second 5 years and $6.66 per Mcf thereafter. GeoMet Operations Other Operations GeoMet Gathering Pipeline Jewell Ridge Pipeline ETNG Pipeline 13
Gurnee Field Operator GeoMet 100% WI 39,000 net acres at 12/31/10 (44% developed) 750 Bcf estimated gas in place Black Warrior B i Basin White Oak Creek Dominion Resources El Paso Proved reserves at 12/31/10 (Sensitivity Pricing*): Energen 86 Bcf Proved (83% developed) Dominion Resources Unproved reserves and unrisked resource potential of ~350 Bcf ~ 5.0 MMcf/day current net gas sales 2011 Plan: El Paso Constellation Black Warrior Methane Cahaba River Black Warrior River Energen Drill & test 5 full wellbores Capex $2.7 million Cahaba Basin Other CBM Projects Alabama *Sensitivity pricing based on NYMEX natural gas forward curve adjusted for the Company s current hedge position and historical location differentials. NYMEX Y X price i averaged d $5.31 $ 31 per Mcff for f the h first fi 5 years, $6.26 per Mcf for the second 5 years and $6.66 per Mcf thereafter. GeoMet High Pressure Pipeline GeoMet Projects Enbridge Pipeline Water Discharge Pipeline CDX Pipeline SONAT Bessemer Calera Pipeline SONAT Interstate Pipeline 14
Garden City Prospect (Shale Gas) Operator GeoMet with 100% WI Approximately 40,000 net leasehold acres Winston County Cullman County Garden City Shallow depth 1,600 to 2,100 feet Blount County Activity to date: 8 coreholes 4 vertical wells 2 horizontal wells Fayette County Walker County Birmingham (Technical Headquarters) St. Clair County Best horizontal well East side 380 Mcf / day (not pumped off before shut in) Best vertical well West side 175 Mcf / day (climbing before shut in) Tuscaloosa County Jefferson County Shelby County Talladega County Unrisked resource potential greater than 250 Bcf 2011 Plan: Return horizontal wells to sales Bibb County Test water disposal options Alabama Gurnee Field Chilton County Coosa County 15
Financial Presentation 16
Recapitalization $40 million preferred equity financing Net reduction in bank debt of $37.2 million New bank credit agreement 3 year term Current borrowing base of $90 million Current borrowings <$ 80 million Market based covenants and pricing 17
Market Value Capital Structure & Debt Ratios Bank Debt at 12/31/10 $ 80,500 Market value of equity, including preferred $ 129,526 stock on an as converted basis * Total Market Capitalization $ 210,026 Debt / Market Capitalization 38% EBITDA ** $ 23,291 Debt / EBITDA 3.46 * Based on market price of $1.78 per share on 3/30/11 and on a conversion ratio of 7.692308 common shares per each preferred share ** Using EBITDA definition in bank credit agreement w hich adds back non-recurring expenses 18
2011 Capital Plan Total Capital Expenditure Budget $13.9 million $0.2 $1.0 $2.7 $1.3 $8.8 Pond Creek Gurnee Leasehold Other Non Cash 19
Hedging Summary As of January 2011 Effective Floor Price 25,000 20,000 $5.91 $5.50 $5.87 Mcf/d 15,000 10,000 72% 61% 48% 5,000 2011 2012 Q1 2013 Hedged Production Current Production 20
Operating Leverage Shallow production decline Estimated at <4% per year; 28 year R/P Low findinganddevelopment development cost 2010 $1.17 per Mcf Ten Year Average $1.60 Low asset intensity Less than 50% of EBITDA required to replace reserves Reduced cost structure 2010 total production costs of $2.12 per Mcf (approximately $1.60 per Mcf cash costs) High leverage to top line growth (production and/or price) 21
Enterprise Value per Mcf of Proved Reserves $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $ GMET GMXR CRK CHK HK RRC GDP SWN PQ GMET trades at 37% of group average 22
Enterprise Value per Mcf of Daily Production $25,000 $20,000 $15,000 $10,000 $5,000 $ PQ CRK GMET GMXR GDP CHK SWN HK RRC GMET trades at 72% of group average 23
Appendix 24
Summary Field Information As of 12/31/10 Appalachian Basin Cahaba Basin Pond Creek Lasher Gurnee (VA, WVA) WVA AL Operator GeoMet GeoMet GeoMet WI 100% 100% 100% Average Coal Depth (feet) 1,100-1,700 800-1,500 700-3,400 Average Coal Thickness (feet) 21 15 50 Average Gas Content (Scf / ton) 460 375 300 Core Holes 14 4 33 Gas Desorption Tests 249 53 600 Net Acres 30,400 8,200 39200 % Developed 56% 12% 44% Productive Wells 264 18 246 Proved Reserves (Sensitivity Pricing*) 135.3 7.0 86.2 % Developed 73% 59% 83% Proved PV10 (Sensitivity Pricing*) $169.6 $4.0 $51.1 *Sensitivity pricing based on NYMEX natural gas forward curve adjusted for the Company s current hedge position and historical location differentials. NYMEX prices utilized averaged $5.31 per Mcf for the first 5 years, $6.26 per Mcf for the second 5 years and $6.66 per Mcf thereafter. 25
Reconciliation of Non GAAP Measures Preliminary Adjusted EBITDA (in 000 s) 2010 2009 Net Income $ 5,792 $ (167,134) Interest Expense 5,124 5,146 Other Expense (income) 34 1 Income Tax Expense (benefit) 5,407 (98,142) Asset Impairment - 257,288 DDA 6,296 12,030 EBITDA 22,652 9,189 Unrealized Hedging Losses (gains) (5,950) 3,995 Unrealized Loss from Change in fair value of derivative liability - Preferred Stock 2,164 - Stock Based Compensation 411 793 Accretion Expense 484 432 Adjusted EBITDA $ 19,762 $ 14,409 26
Reconciliation of Non GAAP Measures Preliminary Adjusted Net Income (in 000 s) 2010 2009 Net Income $ 5,792 $ (167,134) Asset Impairment - 257,288288 Unrealized Hedging Losses (Gains) (5,950) 3,995 Unrealized Loss from Change in fair value of derivative liability - Preferred Stock 2,164 - Accelerated Depreciation - Canada - 2,742 Terminated Transaction Costs 1,403 Effect of Taxes 910 (99,154) Adjusted Net Income $ 4,319 $ (2,263) 27
J. Darby Seré Chairman, President t& CEO dsere@geometcbm.com (713) 287 2253 William C. Rankin Executive Vice President t& CFO brankin@geometcbm.com (713) 287 2257 Stephen M. Smith Treasurer ssmith@geometcbm.com (713) 287 2251 28