Independent Petroleum Association of America 10 th Annual

Independent Petroleum Association of America 10 th Annual Oil and Gas Symposium April 19 – 21, 2004 1 New York, New York

Company Overview Long-lived reserves, high quality, and geographically concentrated in the heart of the oil patch (Texas, Oklahoma, New Mexico, Arkansas and Gulf of Mexico) Reserve replacement ratio of 436% since 2001 (three years) Three year average Finding and Development Cost (all sources) $1. 22/Mcfe Production 70% natural gas and 30% crude oil 5+ year drilling inventory of around 2, 640 onshore locations/232 OCS Blocks High historical drilling success rate – 93% (five year average) We operate approximately 80% of our properties Diversified down the food chain as an operator, producer, gatherer, processor and marketer of our own products 2

Principal Producing Areas Mid-Continent 246 Bcfe 74% gas 29% of total reserves PV-10 $397 million Gulf Coast 72 Bcfe 83% gas 9% of total reserves PV-10 $143 million New Core Area Coalbed Methane Play San Juan Basin 1+ Tcf Potential Permian Basin Corporate Headquarters 3 District & Field Offices 438 Bcfe 43% gas 52% of total reserves PV-10 $633 million Offshore Continental Shelf Offshore 82 Bcfe 76% gas 10% of total reserves PV-10 $308 million

Mineral Leasehold Acreage Ownership Position (Net Acres) As of March 1, 2004 1, 625 371 ND 25, 555 2, 720 WY 1, 804, 535 NV 1, 379, 697 IL 8, 063 2, 634 209, 532 26, 329 720 UT CA 6, 873 480 61, 187 CO 455, 406 1, 814, 731 AZ 41, 726 12, 519 130, 923 1, 508, 156 OK KS 105, 098 12, 873 27, 325 7, 006 140 382 11, 261 IN 310 416 MO 1, 200 AR 80 NM MS TX Developed 589, 999 Acres Undeveloped 470, 343 Acres Leased Option Acreage Remaining Acreage Options 1, 964, 345 Acres 5, 541, 409 Acres Total 8, 566, 096 Acres 4 353, 560 86, 001 67, 579 283 1, 348 1, 308 LA GOM 45, 486 350, 599

New Core Area San Juan Basin Menefee Coal Evaluation (New Magnum Hunter Lease Option Acreage) The Upper and Lower Menefee coals contain an estimated combined resource potential of 1. 88 Tcf of reserves on Magnum Hunter’s acreage position Recoverable gas-in-place is estimated at 504 Bcf and 626 Bcf for the Upper and Lower Menefee coals (at a 60% recovery factor), respectively, for a combined recovery of 1. 13 Tcf Gas content for the coals has been estimated by in-house Magnum Hunter personnel from 20 scf/ton to 70 scf/ton, with the higher of the content being in the Lower Menefee coal Calculation of Resource Potential Property Description Lease: Reservoir: Operator: Counties: State: Grand Total/Southern San Juan Basin Menefee Formation Magnum Hunter Resources/CDX Mc. Kinley, Sandoval, San Juan, Cibola, Bernalillo, Valencia, Catron, Socorro New Mexico Volumetric Calculation Gas Content (scf/ton) Coal Density (g/cc) Coal Density (ton/acre-ft) 44 Recoverable GIP (Mscf/acre-ft) 63. 5 1. 750 Eff. Drainage Radius (ft) 48, 133 2379 Net acre-ft 17, 800, 876 Area (acres) 167, 089 Net Pay (ft) 107 GIP (Bscf) 1, 883 Recovery Factor (%) 60% Dry Gas Ultimate Recovery (Bscf)1 1, 130 (1) The reserves presented herein may differ from the forecast due to economic limits reached. Stratigraphic Column Kirkland SH The Menefee Formation of the Upper Cretaceous Mesaverde Group contains abundant coal beds that are estimated to contain 34 Tcf in the San Juan Basin Lewis Sh Cretaceous Mesaverde Group Until recently, the resource potential in the Menefee coals was overlooked due to the development and exploitation of the Fruitland coal Fruitland Coal Pictured Cliffs Ss Cliff House Ss Menefee Fm Point Lookout Ss Mancos Sh 5 Dakota Ss Coal Deposit Upper Menefee Coal Structure Map

U. S. Coalbed Statistics 100 Net Coal Thickness San Juan (Menefee Coal) 95 1000 900 Piceance Powder River 80 70 60 Canaba 50 40 30 Black Warrior 10 Arkoma 600 400 Green River Cherokee Forest City N. Appalachia Powder River Coal Density 1. 00 Recovery Factor 0. 80 1. 70 Green River 1. 60 Cherokee Raton Black Warrior Piceance 1. 32 Powder River San Juan (Fruitland Coal) San Juan (Menefee Coal) Uinta Recovery Factor (fraction) 1. 80 1. 40 San Juan (Menefee Coal) 0 0. 90 1. 50 Uinta Raton C. Canaba Appalachia 50 1. 90 Coal Density (g/cc) Black Warrior 100 Cherokee San Juan (Fruitland Coal) 500 200 N. Appalachia 0 2. 00 700 300 Arkoma Uinta C. Appalachia 20 Raton Forest Green City River Piceance 800 San Juan (Fruitland Coal) Gas Content (scf/ton) Net Coal Thickness (feet) 90 Natural Gas Content 0. 70 0. 60 0. 50 Green River Powder River c. 1. 10 0. 00 Raton San Juan (Menefee Coal) Uinta Appalachia Cherokee 0. 30 0. 20 Source: Merrill Lynch Black Warrior 0. 40 1. 20 1. 00 San Juan (Fruitland Coal) Piceance

Acquisition/Divestiture History Timing is Key to Profitable Growth $6. 00 Peak lll ($1. 21/mcfe) So. TX 11/02 ($33 MM) Louis Dreyfus 08/00 ($15. 8) 60/40 Gas/Oil 12 Mth. Strip Misc. Sales 09/02 – 12/02 ($17 MM) $5. 00 GE Capital 06/00 ($23 MM) Average Transaction Price So. LA 05//03 ($13. 4 MM) G. E. Capital 09/02 ($50 MM) Per MCFE $4. 00 Peak l ($0. 87/mcfe) $3. 00 Peak ll ($1. 06/mcfe) Mallon 09/01 $31. 3 MM Dynegy 11/99 $4. 3 MM Panoma 06/96 $34. 7 MM Trough l ($0. 88/mcfe) TEL Offshore 03/98 $10. 4 MM Permian Basin 04/97 $133. 8 MM $2. 00 Trough Ill ($0. 83/mcfe) Prize Energy 03/02 $550 MM Vastar 06/99 $32. 5 MM Trough ll ($0. 75/mcfe) Spirit 76 12/98 $25. 5 MM $1. 00 01 /05 7 /96 08 /02 /96 02 /28 /97 09 /26 /97 04 /24 11 /98 /20 /98 06 /18 /99 01 /14 /00 08 /11 /00 Sources: Morgan Stanley Equity Research; Herold’s Company 03 /09 /01 10 /05 /01 05 /10 /02 12 /06 /02 07 /03 12 /24 /03

2003 Expenditures 2004 Capital Budget 2003 $175 Million Permian Basin $39 Million 23% Mid-Continent $11 Million Gulf Coast (Onshore) $6 Million 6% 3% 2004 $150 Million Permian Basin $50 Million Mid-Continent $10 Million Gulf Coast (Onshore) $5 Million 7% 3% 33% 68% Gulf of Mexico $119 Million 8 57% Gulf of Mexico $85 Million

Gulf of Mexico Magnum Hunter GOM Lease Ownership and Discoveries Gulfport Louisiana Baton Rouge New Orleans Lake Charles Lafayette Beaumont MP 178 West Cameron Main Pass East Cameron High Island South Marsh Island Vermillion Eugene Island Ship Shoal South Timbalier ST 265 Grand Isle Ewing Bank Green Canyon Lease Sale Blocks Undeveloped Leases Gulf of Mexico Currently Drilling New Discoveries Currently Producing 9

Offshore Gulf of Mexico Large inventory of 174 OCS Blocks (800, 000 gross acres) - 55 New Blocks awarded at 2004 Central GOM Sale (Highest Bidder Overall) Over 25 Blocks have Deep Shelf identified prospects Additional 25% net profits interest in 17 additional OCS Blocks with 29% ownership in TEL Offshore Trust All 3 -D seismic controlled with new vintage data Prospects located near existing production facilities Reserve potential of 10 -500 Bcfe per prospect 81% drilling success rate with 79 out of 97 GOM wells completed thru December 31, 2003 GOM rate of return (sinception thru December 31, 2003) Proved & Probable Proved, Probable & Possible 10 ROI 1. 48 2. 15 2. 39 ROR 13. 2% 22. 5% 24. 1%

Offshore Gulf of Mexico Discoveries on Production since entering GOM in May 1999 Project Area East Cameron 73, 184, 185, 344, 346, 364 345, 360, 377 Eugene Island 148, 302, 355 397 High Island A-153 A-441 Main Pass 160, 163, 164, 178, 263 107, 108 South Marsh Island 24, 35, 93 Ship Shoal 28, 38 322 358 South Timbalier 250, 264, 265 274, 275 Vermilion 61, 100, 117 84 West Cameron 347, 403, 416, 417, 426, 428, 472, 488 11 Production Operator Gross Per Day MHR Net Per Day Remington W & T Offshore 20. 6 3. 6 Remington Hunt Oil W & T Offshore 65. 9 11. 3 SPN Resource Remington . 9 . 08 Magnum Hunter Kerr Mc. Gee 34. 7 13. 5 Remington 26. 4 6. 8 Callon Remington ATP 26. 8 4. 7 Magnum Hunter Spinnaker 16. 5 7. 0 Remington W & T Offshore 31. 3 8. 1 Remington 48. 4 15. 0 271. 5 70. 1

Offshore Gulf of Mexico Recent Discoveries/Production Pending Project Area Production Operator WI Estimated First Production Date Potential Daily Net Production (MMCFE) Eugene Island 304 Remington 50% 2 nd Qtr. 2004 5. 0 W. Cameron 458 Remington 40% 2 nd Qtr. 2004 4. 0 W. Cameron 457 Remington 40% 2 nd Qtr. 2004 4. 0 Remington 40% 3 rd Qtr. 2004 3. 5 Total Estimated (MHR Net): 16. 5 East Cameron 205 12

2004 Offshore Exploration / Development Working Interest 15% Estimated Gross Reserves 15 BCFE Depth 8, 900’ Spud Date Drilling Prospect Ship Shoal 358 A-2 Operator ATP W. Cameron 295 Magnum Hunter 30% 60 BCFE 17, 668’ Drilling Main Pass 234 Newfield 25% 23 BCFE 14, 500’ Drilling W. Cameron 567 Gryphon 37. 5% 30 BCFE 12, 500’ Drilling East Cameron 205 Remington 40% 20 BCFE 8, 650’ Completed Ship Shoal 165 Remington 25% 40 BCFE 14, 000’ Drilling Main Pass 99 Forest 25% 30 BCFE 14, 100’ Drilling Vermillion 241 Remington 50% 16 BCFE 10, 800’ 2 nd Qtr. S. Tim. 261/262 Magnum Hunter 50% 100 BCFE 15, 500’ 2 nd Qtr. W. Cameron 398 Remington 40% 15 BCFE 7, 730’ 2 nd Qtr. S. Marsh Island 24 A-3 Remington 30% 15 BCFE 7, 383’ 2 nd Qtr. S. Marsh Island 113 Remington 50% 10 BCFE 7, 000’ 2 nd Qtr. Total Potential Gross Reserves: Total Potential MHR Net Reserves: 13 354 BCFE 106 BCFE

Offshore Gulf of Mexico Production Initiated Drilling in GOM - 1999 te = h Ra owt l Gr MCFE Per Day ua Ann 40, 236 67, 500 89% 65, 000 56, 910 56, 232 57, 500 52, 599 40, 958 40, 630 42, 022 34, 650 25, 056 7, 600 3, 300 1999 14 2000 2001 2002 2003 2004 E

NEW MEXICO MORROW – ATOKA - STRAWN PROGRAM Two Drilling Rigs Working Continuously • 44 wells drilled successfully • 42 wells completed • Average per well IP = 2. 0 MMCFE per day (gross) • 2 new wells in various completion stages • Recently acquired farm-ins on 20, 000 gross mineral acres, with 30 to 50 new drilling locations identified. Currently negotiating new farm-ins on an additional 15, 000 gross mineral acres to further increase acreage position Jan. 96 15 Jan. 97 Jan. 98 Jan. 99 Jan. 00 Jan. 01 Jan. 02 Jan. 03 Dec. 03

S. E. New Mexico Gas Production All Sources 45, 000 te = h Ra 30% Net Production – Mcfe/Day owt ded oun l Gr nua An p Com 31, 989 24, 486 20, 443 15, 672 16 Year-End Estimate

Onshore Inventory Locations (Including Recompletions) Proved Developed Non-Producing* Proved Undeveloped* Probable/ Possible* Estimated Unbooked Total Abell (Texas) 0 3 6 Cumberland (Oklahoma) 8 7 29 0 44 21 2 31 20 74 Goldsmith Mash Field Area (Texas) 0 17 19 5 41 Keystone (Texas) 1 5 3 10 19 Panoma Area (Oklahoma/Texas) 0 101 42 100 243 Coal Bed Methane (New Mexico/Colorado) -- -- -- 1, 000 33 70 62 50 215 9 0 5 30 44 War-Wink (Texas) 42 3 10 5 60 Westbrook (Texas) 12 81 0 0 93 Other 117 169 265 250 801 Total 243 458 466 1, 473 2, 640 Eola-Robberson (Oklahoma) Southeast New Mexico Walnut Bend Field Area (Texas) 17 * As estimated by third party engineering firm De. Golyer and Mac. Naughton

Drilling Activity – Gross Wells Drilled 2003 Drilling Activity ($174. 6 million) Exploration Development Total Successful P&A’d Total 17 98 115 8 1 25 23 93 116 6 2 9 85 94 4 2 6 87 100 69% 98% 94% 34 52 86 2 0 2 36 52 88 94% 100% 98% 11 15 26 3 2 5 14 17 31 79% 88% 84% 9 99 124 Success Ratio 68% 99% 93% 2002 Drilling Activity ($127. 0 million) Exploration Development Total 2001 Drilling Activity ($159. 7 million) Exploration Development Total 8 29 95 124 13 79% 98% 94% 2000 Drilling Activity ($60. 7 million) Exploration Development Total 1999 Drilling Activity ($21. 7 million) 18 Exploration Development Total

Peer Group 2003 Finding and Development Costs per Mcfe (All Sources – three year average) Average: $ 1. 35 Median: $ 1. 29 19 Source: Company Data

Average Daily Production (MCFE) Net Daily Production Growth C ed und mpo o al G nnu = ate th R ow r 220, 000 31% 194, 338 200, 143 A 91, 292 74, 777 Mid-Point Est. Note: 20 Excludes net daily production lost from asset sales of 39, 926 MMcfe per day over this period.

Production by Area Gulf Coast (onshore) 17 MMcfe/d Mid-Continent 44 MMcfe/d Permian Basin 86 MMcfe/d 8% 22% 42% 28% Gulf of Mexico 57 MMcfe/d Production By Product Oil Reserves By Category PDP Gas 31% 69% PDNP 64% 10% 26% PUD 21

Cash Flow Per Share (Debt Adjusted) Five Year Annual Growth Rate Large/Mid/Small Caps 1998 - 2002 32. 4% MH R PERCENTAGE % Change 22 Source: Lehman Brothers

History of Reserve Growth Billion Cubic Feet Equivalent Natural Gas Equivalents (Bcfe) 837 Bcfe po Com 367 Bcfe nnua d. A unde l Gro 378 Bcfe 55% 59% 45% 63% 41% 66% 37% 34% 98% Drilling Success Mallon Acquisition Exploration 23 838 Bcfe 2% = 3 Rate wth Prize Acquisition Development & Exploitation 93% Drilling Success Acquisitions & Mergers

Peer Group Three Year Average All Sources Reserve Replacement Ratio (2001 – 2003) Average: 276% 861% 627% Median: 260% 436% 552% 485% 411% 277% 264% 270% 324% 329% 260% 313% 216% 149% 102% 164% 173% 189% 140% 82% 37% 24 Source: Company Data 214% 174% 224% 249% 226% 280% 455% 576%

Yearly Growth in Revenues $395, 600* nual e An th Grow = Rate ag Aver 1998 $325, 014 ($000’s) $127, 510 $51, 400 40% $265, 869 $152, 806 $69, 626 1999 2000 2001 2002 2003 2004 E * Average consensus of the ten Equity Analysts that currently follow Magnum Hunter Resources, Inc. The Benchmark Price Consensus from these analysts for 2004 is $5. 38 per Mcf and $30. 76 per Barrel. 25

Operating Efficiency Improvements Total Wells/Operated Wells 3, 042 2, 168 d n ed A G nual nt = 2, 230 ound $0. 22 5, 612 3, 241 Comp 22% 5, 591 4, 428 Per Mcfe Produced Co un mpo row th in Cou Well G & A Expenses per Mcfe Produced ed An nual D ecline $0. 21 in Ov erhea d = 8% $0. 19 $0. 17 4, 399 * Effective Jan. 1, 2003 Magnum Hunter began expensing the fair market value of stock options pursuant to SFAS No. ’s 123 and 148. For the year ended Dec. 31, 2003 Magnum Hunter recorded a non-cash compensation expense of $3 million which is reflected in 2003’s G&A total of $15. 3 million. The 2003 G & A expense per Mcfe of $0. 17, as reflected above, has been adjusted for the 2003 SFAS No. ’s 123 and 148 non-cash charge of $3 million in order to be congruent with prior years. 26

Peer Group 2003 G & A Costs per Mcfe Average: $. 25 Median: $. 24 27 Source: Company Data Note: Excludes non-cash charge for stock options expense

Condensed Balance Sheets ($ in Thousands) Dec. 31, 2002 Dec. 31, 2003 Current Assets $ 100, 337 $ 97, 973 Dec. 31, 2001 Dec. 31, 2000 Dec. 31, 1999 $ $ $ 25, 106 34, 838 15, 712 1, 095, 883 Other Assets 1, 001, 609 419, 837 260, 532 265, 195 69, 672 Net Property, Plant and Equipment 70, 074 9, 442 20, 242 23, 115 TOTAL ASSETS $ 1, 265, 892 $ 1, 169, 656 $ 454, 385 $ 315, 612 $ 304, 022 Current Liabilities $ 105, 503 $ 128, 996 $ 48, 713 $ 30, 717 $ 17, 026 Bank Debt 165, 000 125, 000 155, 000 51, 120 94, 800 Senior Debt and Convertible Notes 425, 000 429, 466 140, 000 Other Liabilities 180, 713 135, 998 3, 232 359 644 TOTAL LIABILITIES 876, 216 819, 460 336, 411 222, 196 252, 470 STOCKHOLDER’S EQUITY 389, 676 350, 196 117, 974 93, 416 51, 552 TOTAL LIABILITIES & STOCKHOLDERS’ EQUITY Debt/Book Capitalization Ratio Debt/Market Capitalization Ratio 28 $ 1, 265, 892 60% 50% $ 1, 169, 656 61% 57% $ 454, 385 71% 49% $ 315, 612 67% 37% $ 304, 022 82% 80%

Magnum Hunter Senior Unsecured Convertible Notes Issuer: Book-running managers: Proceeds: Status: Form of registration: Maturity: Denomination: Issue/redemption price: Coupon (q. ): Yield-to-maturity (q. ): Initial coupon rate: Magnum Hunter Resources, Inc. ("MHR") Deutsche Bank Securities, Bank of America $125 million Senior, Unsecured Rule 144 A for life December 15, 2023 $1, 000 per bond 100% of par 3 month LIBOR (Currently 1. 11%) 3 month LIBOR 1. 17000% (Official BBA USD Libor fixing rate at 11: 00 AM London time on December 11, 2003) Conversion premium: 45. 0% Reference share price: $8. 41 (NYSE closing price on December 11, 2003) Conversion price: $12. 19 Conversion ratio: 82. 0345 shares per $1, 000 bond (approximate) Call feature: Unconditionally callable after year 5 Put feature: Puttable in years 5, 10, 15 Conversion type: Net share settle Contingent conversion: Yes, trigger at 110% Contingent payment: None Dividend protection: Full dividend protection for the life of the instrument via conversion price adjustment Trade date: December 12, 2003 Settlement date: December 17, 2003 Interest payment dates: March 15, June 15, September 15 and December 15 (quarterly in arrears) First coupon date: March 15, 2004 Cusip: 55972 FAE 4 ISIN: US 55972 FAE 43 Use of proceeds: Magnum Hunter has used the net proceeds from the offering to repay outstanding indebtedness under Magnum Hunter's revolving credit facility

Interest Expense Per Mcfe Produced $0. 74 $0. 67 $0. 61 $0. 58 30 2002 2003 $0. 55 2004 E

Net Cash Margin Improvement Old commodity hedges gone as of December 31, 2003 Sold bulk of higher lifting cost properties Redeemed $140 million of 10% high yield debt Placed $125 million convertible debt at 1. 11% interest rate (floating) $5. 09 $4. 08 Realized price per Mcfe (net) Cash margin as a percent of realized price per Mcfe Net cash margin percent $3. 49 41% 42% $3. 70 $3. 63 $3. 36 42% $2. 99 45% $1. 45 1 st Qtr 2002 31 $1. 41 2 nd Qtr 3 rd Qtr 2002 46% $3. 92 51% 48% 41% $3. 02 $1. 85 $1. 22 59% $3. 92 $1. 72 $1. 87 $2. 01 3 rd Qtr 2003 4 th Qtr 2003 $1. 50 4 th Qtr 2002 1 st Qtr 2003 2 nd Qtr 2003 1 st Qtr 2004 E Note: Net cash margin is defined as the realized price per Mcfe less LOE, production taxes, G & A expense (recurring), and interest expense.

Gas Gathering, Processing and Marketing Strategy Panoma Gas Gathering System (100% ownership MHR) - 449 miles of pipeline - 15. 5 Mmcf per day throughput Mc. Lean Gas Processing Plant (50% ownership MHR) - Modern cryogenic gas processing plant 980 barrels per day liquids production/23. 0 Mmcf/D capacity (65% utilized) Walker Creek Processing Plant (15% ownership MHR) - Propane refrigeration plant - 240 barrels per day liquids/12 Mmcf/D capacity (35% utilized) Madill Gas Processing Plant (50% ownership MHR) - Modern cryogenic gas processing plant and gathering system - 970 barrels per day liquids production/18 Mmcf/D capacity (78% utilized) Elmore City Processing Plant (100% ownership MHR) - Modern cryogenic gas processing plant and gathering system - 980 barrels per day liquids production/35 Mmcf/D capacity (30% utilized) Acquire or build new systems to complement existing production Seeking ways to monitize this asset base and continue in operating control 32

Financial Performance (000’s) Revenues Operating Profit $140. 6 $395. 6 $325. 0 $265. 9 $92. 7 $68. 9 $127. 5 $152. 8 $50. 3 $69. 6 $48. 1 $15. 1 EBITDA Net Income $61. 4 $251. 2 $192. 3 $155. 3 $26. 1 $22. 3 $92. 4 $13. 5 $75. 9 37. 2 33 $15. 5 ($6. 8) Note: Forward estimates for 2004 are derived from average consensus of the ten equity analysts that currently follow Magnum Hunter. The Benchmark Price Consensus from these analysts for 2004 is $5. 38 per Mcf and /$30. 76 per Barrel.

Oil & Natural Gas Commodity Hedges Year 2004 2005 Gas % Mmcf Hedged 85 50 52% (i) 23% (ii) Oil Bbls % Hedged 5, 865 0 62% (i) 0 (ii) Natural Gas Price Commodity Hedges 2004 - 85 Mmcf/d at $3. 76 - $5. 78 per Mmbtu 2005 - 50 Mmcf/d at $4. 05 - $6. 32 per Mmbtu Oil Price Commodity Hedges 2004 - Collars 5, 865 BOPD at $23. 87 - $29. 85 per Bbl (i) (ii) 34 Based on 2004 mid-point guidance Based on 2004 4 th quarter mid-point guidance

Commodity Price Sensitivity 2004(i) ) 2005(ii $0. 10 increase in gas price – Earnings per share $0. 05 $0. 03 $1. 00 increase in oil price – Earnings per share Note: (i) Based upon 2004 mid-point production guidance assuming $25 per barrel oil and $4 per Mcf gas and existing 2004 commodity hedges (ii) Based upon 2004 mid-point production guidance assuming $25 per barrel oil and $4 per Mcf gas and existing 2005 commodity hedges 35

Management’s Estimate of Magnum Hunter Net Asset Value (Millions) Per Share* $1, 481. 7 $19. 60 Estimated Value of Gathering, Marketing, and Processing Segment Assets: 7 times 2003’s Estimated EBITDA of $10. 0 million $70. 0 $0. 93 Book Value of Other Assets Excluding Goodwill (12/31/03) $13. 2 $0. 17 Undeveloped Acreage, Net (12/31/03) 119, 744 Domestic Onshore Acres @ $100. 00 per acre 350, 599 Domestic Offshore Acres (100% GOM) @ $200. 00 per acre $12. 0 $70. 1 $0. 16 $0. 93 San Juan Basin New Mexico CBM Leasehold Position, 1. 5 Million Acres @ $72. 00 per acre $108. 0 $1. 43 Leasehold Option Acreage Position - Other, 6. 3 Million Acres @ $3. 25 per acre Working Capital, Net (12/31/03) Non-Current Derivative and Other Liabilities (12/31/03) $20. 5 ($5. 2) ($34. 2) $0. 27 ($0. 07) ($0. 45) ($595. 5) ($7. 88) Proved Reserves totaling 838. 4 Bcfe (6: 1 conversion ratio 58. 9% natural gas, $5. 24 per Mcf & $30. 57 per Bbl) (Before Tax Present Value Discounted @10% as of 12/31/03) Long-Term Debt, Net (12/31/03) NOL Carry-Forward, $70. 2 Million at December 31, 2003 @ 20% of estimated market value $14. 0 $0. 19 Outstanding Common Stock Options @ 12/31/03 – 6, 740, 764 with an average strike price of $6. 36 per share $42. 9 $0. 57 $1, 197. 5 $15. 85 Management’s Estimated Per Share Net Asset Value as of December 31, 2003 (Unaudited) * Management’s Estimated NAV (Unaudited) $15. 85 $15. 85 NAV Trading % 55% 60% 65% 70% 80% 90% 100% 110% 36 * Based on 75. 6 million fully-diluted common shares as of December 31, 2003. Implied MHR Share Price $8. 72 $9. 51 $10. 30 $11. 10 $12. 68 $14. 27 $15. 85 $17. 44

Liquidity and Market Value Institutional Ownership = 59% of Float as of December 31, 2003 Thousands Millions $800 e reas n Inc % = 56 $726 MM $700 o izati n n nd A pou Com ital Cap rket a ual M $600 $547 MM $500 $400 $300 $200 $78 MM $100 $0 * 2000 37 * As of April 12, 2004 2001 2002 2003 2004

Equity Research Analyst Coverage Firm Analyst(s) Report Date Recommendation Jefferies & Company, Inc Frank D. Bracken, III Leo P. Mariani 03/05/04 Buy Johnson Rice & Company L. L. C. 03/05/04 Outperform Southwest Securities Ronald E. Mills Ken Beers John Gerdes 03/05/04 Neutral Stanford Group Company Phil Dodge 03/09/03 Hold Raymond James & Associates, Inc. Wayne Andrews Jeffrey L. Mobley Pavel Molchanov 03/05/04 Strong Buy Friedman Billings Ramsey David M. Khani Frank M. Roebuck Deutsche Bank Securities Inc. John A. Bailey Neil P. Brown Jeffrey S. Wyll A. G. Edwards & Sons, Inc. Greg Mc. Michael Chris Pikul 12/22/03 Buy/Speculative Lehman Brothers Jeffrey W. Robertson Michael A. Sullivan 11/05/03 Underweight (Company) Neutral (Sector) 38 03/04/04 Outperform Buy

Shareholder Return $100, 000 invested in Magnum Hunter at December 31, 1990, when the Company went public on the Boston Stock Exchange, would be worth approximately $4. 3 million today. This calculates to an annual 33% compounded return of 33% over the past 12 years (see Note). The Oil and Gas Journal recently ranked Magnum Hunter as the number one fastest-growing company based on growth in stockholders equity. Magnum Hunter’s stockholder equity nearly tripled last year from $118 million to $350 million. Note: Includes the effect of $6. 50 warrants issued in 2000. Shareholders received one warrant for every three shares of Magnum Hunter common stock. Assumes warrants were sold at the average closing price for the first ten trading days ($0. 89 per warrant). Also includes the effect of $15. 00 warrants issued in 2002. Shareholders received one warrant for every five shares of Magnum Hunter common stock. Assumes warrants were sold at the average closing price for the first ten trading days ($1. 12 per warrant). 39

Investment Considerations Diversified, long lived, and stable reserve base Replaced 436% of last three years production at all sources finding and development cost of $1. 22 per Mcfe Large portfolio of low cost, low-risk exploitation projects located in core operating areas Significant exploration potential with 232 OCS lease blocks in the Gulf of Mexico Shelf, 25 of which are Deep Shelf Consistent balance sheet improvement Experienced low cost operator with significant operating control Three year growth in proved reserves per share of 15% compounded annually and increase in production per share of 9% compounded annually 40 Management team with significant ownership interest

Disclosure Regarding Forward-Looking Statements The information in this release includes certain forward-looking statements that are based on assumptions that in the future may prove not to have been accurate. Those statements, and Magnum Hunter Resources, Inc. ’s business and prospects, are subject to a number of risks, including volatility of oil and gas prices, the need to develop and replace reserves, the substantial capital expenditures required to fund its operations, environmental risks, drilling and operating risks, risks related to exploration and development drilling, uncertainties about estimates of reserves, competition, government regulation, and the ability of the Company to implement its business strategy. These and other risks are described in the Company’s reports that are available from the SEC. 41

42 16 March 2018