exv99w1

EX-99.1 2 h37726exv99w1.htm SLIDE PRESENTATION exv99w1

Exhibit 99.1

Onshore Review July 2006 The Houston Exploration Company 1100 Louisiana, Suite 2000 Houston, Texas 77002 713-830-6800 www.houstonexploration.com The Houston Exploration Company

Executive Summary Operations Summary South Texas Optimizing and Expanding Core Producing Areas Rocky Mountains Preparing for the Future: Unlocking Potential Arkoma Basin Optimizing and Expanding Core Producing Areas: An "Efficiency" Play East Texas Applying Core Competencies and Expanding Asset Base Financial Summary Agenda

This presentation includes "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. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact, such as estimated reserves and projected drilling and development activity. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including the cautionary statements contained in this presentation and risks and uncertainties discussed in the company's Annual Report on Form 10-K, as amended, for the year ended December 31, 2005, and other filings with the Securities and Exchange Commission. These risks include, among others, the terms, timing and impact of our business strategy and any other strategic alternative, if any, ultimately selected by the Board, price volatility, the business outlook, the impact of onshore asset concentration, the risks associated with the consummation and successful integration of acquisitions, the impact of hurricanes, the risk of future writedowns, the impact of hedging activities, the accuracy of estimates of reserves and production rates, production and spending requirements, the inability to meet substantial capital requirements, the market and other factors for stock repurchases, the constraints imposed by the Company's outstanding indebtedness, the relatively short production life of the Company's reserves, reserve replacement risks, drilling risks and results, the competitive nature of the industry, and other risks and factors inherent in the exploration for and production of natural gas and crude oil. The Company assumes no obligation to update any forward-looking statements contained in this presentation. 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 "speculative", "EUR", "recoverable", "upside", "probable", and "possible/potential", 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. Oil and gas exploration is inherently risky. There is no assurance that the Company can realize any of this potential. Forward-Looking Statements

Executive Summary

Company Profile Onshore operator, focused in U.S. tight-gas basins 1Q06 total production of 312 MMcfe/d (onshore = 202 MMcfe/d) YE05 onshore reserve base of 616 Bcfe Developing significant gas resource 7,500 potential locations 2.5 Tcfe of net proved & potential Steady operational track record Committed to enhancing shareholder value Implementing strategic restructuring announced November 2005 Executing on $200 MM share repurchase program Reviewing additional strategic alternatives + +

Successfully Executing Onshore Transformation November 2005 Announced strategic restructuring plan Sell GOM assets, redeploy onshore, repurchase shares March 2006 Sold TX GOM assets $220 MM gross sales price May 2006 Began repurchasing shares 1,177,000 shares repurchased to date (4% of outstanding) June 2006 Sold LA GOM assets $590 MM gross sales price Retained 18 offshore exploration blocks Announced review of strategic alternatives to complement/replace existing business plan Engaged Lehman Brothers Alternatives include, but not limited to, recap through additional share repurchases or special dividend; operating partnerships and/or strategic alliances; and sale or merger

Core Onshore Operations Support Value Creation Rockies '05 Proved Reserves: 27 Bcfe % of Onshore: 4% Upside Potential: 1,250 Bcfe '06 Program: 200+ wells '06 Capex: $102 MM Arkoma '05 Proved Reserves: 151 Bcfe % of Onshore: 25% Upside Potential: 70 Bcfe '06 Program: 75+ wells '06 Capex: $36 MM South Texas '05 Proved Reserves: 374 Bcfe % of Onshore: 61% Upside Potential: 450 Bcfe '06 Program: 90+ wells '06 Capex: $215 MM East Texas/Other '05 Proved Reserves: 64 Bcfe % of Onshore: 10% Upside Potential: 155 Bcfe '06 Program: 30+ wells '06 Capex: $90 MM* *Includes $22 MM for acquisition, closed April 25, 2006 Note: Sold GOM proved reserves in 2006 totaling 245 Bcfe. Gross sales price was $810 MM prior to adjustments.

THX Focus Area THX Focus Area THX Focus Area Source: Potential Gas Committee, 2004 Focused in Premier U.S. Onshore Basins with Significant Gas Potential Remaining 0 10 20 30 40 50 60 70 80 Appalachians Tx Gulf Coast Anadarko Basin, Palo Duro Uinta/Piceance Permian Powder River Greater Green River San Juan East Texas Louisiana- Mississippi Salt Basins Area Resource Potential (Tcf) Speculative Possible Probable

Produced Proved Potential Gas in Place STX 1304 374.2 447.8 912 UT 0.8 8.2 790 1950 CO 0 18.5 458.5 1112 ARK 94 151.1 68 134 ETX 22 61.3 154.7 103 Proved & Potential: 2.5 Tcfe + Potential PUD STX 491 146 UT 3200 20 CO 3316 82 ARK 213 81 ETX 304 88 High-Impact Areas Provide Future Drilling Inventory Inventory: 7,500 Wells +

Onshore Strengths More stable, predictable production Lower operating costs Longer reserve life Reserve Base Production Acres Reserves Acquired '96 90.5 16 99 112.5 '97 219 30 127 0 '98 225.1 43 126 65.9 '99 304 44 117 0 '00 331 44 110 0 '01 300.2 43 126 84.8 '02 413.3 57 156 38.7 '03 484.6 63 417 23.4 '04 493.2 68 619 8.8 '05 516.3 68.6 970 99.7 Proven Onshore Growth Record CAGR Reserves 13% Production 18%

STX ARK ETX CO UT Other RM Other '00 83 18 3 0 0 0 16 '01 83.4 21 2 0 0 0 10.5 '02 121.6 20.4 1.7 0 0 0 11.6 '03 140.1 23 1.6 0 0 0 8.5 '04 142.3 37.5 1.9 0 0.8 0 3.6 '05 134.2 43.3 5 0.2 4.4 0 1 '06E 139.7 38.4 15 5.8 6 0 1 '07E 145.2 41.4 24.7 12 21.9 0.5 0.9 STX ARK ETX CO UT Other RM Other '00 46.25 5.56 0.09 22.5 '01 133.03 14.08 0.01 29.99 '02 130.92 7.7 -0.14 17.33 '03 117.17 16.59 2.08 8.93 4.59 38.19 '04 141 27.5 3.32 7.05 31.6 3.25 13.67 '05 329.6 26.8 60.2 25.09 35 16.87 '06E 215 36 90 29 63 10 0.2 '07E 212 36 97 29 82 10 0.23 Total Additions Acquisitions '00 0.82 1.18 0 '01 1.65 1.87 0.81 '02 1.18 1.26 1.08 '03 1.58 1.44 1.17 '04 1.86 1.64 0 '05 2.62 2.58 2.02 STX ARK ETX CO UT Other RM Other '00 28 20 1 '01 36 35 5 '02 63 24 0 '03 77 51 2 '04 76 79 2 26 5 4 '05 95 61 16 107 36 6 0 '06E 111 83 45 170 87 7 3 '07E 109 78 68 127 188 8 5 Steady Onshore Performance with Increased Drilling Production Wells F&D Capex Note: '06E and '07E as of May 2006

Disciplined Acquisitions Have Provided Substantial Growth and Inventory 31% 21 16 ETX, '06 Willow Springs 16% 102 88 STX, '05 Rincon, TCB and Others ETX, '05 STX, '02 STX, '01 STX, '96 143% 850 350 Total 294% 67 17 Henderson and Blocker -8% 34 37 NE Thompsonville 82% 155 85 Webb County 340% 471 107 Charco EUR Percent Change EUR at Acquisition (Bcfe) Acquisition EUR as of 6/30/06 (Bcfe)

Portfolio Management Process Value Steps STX ARK ETX CO UT Value Process Concept aaa aaa aaa aaa aaa Risk/Portfolio Mgmt. Asset Accumulation aaa aaa aaa aaa aaa Validate/Explore aaa aaa aaa aaa aa Develop aaa aaa aaa aa Efficiency Optimize aaa aaa Harvest Portfolio Mgmt. Technology or Uncertainty Proved aaa Understood Emerging aa Uncover Frontier a Unclear Process in Place to Grow Core Operations within Resource Plays

Onshore Snapshot YE05 Proved Reserves (Bcfe) 374 27 151 64 616 % of Total Onshore 61 4 25 10 100 Upside Potential (Bcfe) 450 1,250 70 155 1,925 R/P (years) 7+ 10+ 9+ 14+ 8+ 1Q06 Production (MMcfe/d) 145 6 40 11 202 % of Wells Operated 88% 74% 70% 98% 82% 2006 Capital (MM$) 215 102 36 90 443 Drilling Program (wells) 90+ 200+ 75+ 30+ 395+ Avg. Well Cost (MM$) 1.1 - 4.0 0.3 - 1.8 0.5 - 0.8 1.5 - 2.0 Avg. Gross EUR/well (Bcfe) 0.7 - 2.0 0.3 - 1.5 0.3 - 1.0 0.6 - 1.5 Avg. Rigs 6 - 7 3 - 4 3 3 Rockies STX ETX Arkoma Total

ROR @ $5.00 NYMEX ROR @ $7.00 NYMEX ROR @ $9.00 NYMEX Rincon Gas 0.937 1 1 Rincon Oil 0.558 1 1 Ark - .5 Bcfe 0.222 0.49 0.781 TCB 0.164 0.568 1 Colorado 0.149 0.376 0.61 ETX - 1.0 Bcfe 0.13 0.286 0.465 Charco Perdido 0.101 0.417 0.902 Charco Perdido/Lobo 0 0.267 0.608 Utah - .75 Bcfe 0 0.218 0.458 Utah - .43 Bcfe 0 0 0.143 Strong Well Economics

South Texas Strategy Continue successful development drilling at major leasehold positions 600+ well inventory with six-to-seven rigs Expand Vicksburg drilling program through asset development and exploration Fully evaluate 3-D seismic Leverage efficiencies of existing competitive position Test three exploration projects over the next 12 months Optimizing and Expanding Core Producing Areas

Wilcox/Lobo Vicksburg Focused Operations: South Texas 4th Largest Producer in RRC District #4 as of April 2006 THX Acreage 3-D Coverage 0 - 10 Mi. Well Count Current Inventory Vicksburg 121 167 Wilcox/ Lobo 683 206

South Texas Reserve Growth '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 Legacy 106 127 137 143 164 230 299 315 327 374 KMG Source: Netherland Sewell & Assoc. CAGR 15%

Completed Dry '96 1 3 '97 22 5 '98 17 3 '99 22 1 '00 25 3 '01 29 7 '02 55 11 '03 54 20 '04 64 21 '05 72 12 '06E 100 '07E 109 South Texas Drilling: Active and Successful Note: '06E and '07E as of May 2006

Rockies Strategy Increase Uinta exploitation (develop and delineate) Continue to develop production and drill "pilot" projects Build infrastructure, expedite permits, lower water handling costs Expand Niobrara development Continue 3-D seismic and field expansion Add gathering to maintain low field pressures and optimize water handling Explore Northern Uinta acreage Additional Niobrara acreage Other tight plays Preparing for the Future: Unlocking Potential

Kerr McGee/Anadarko 180 MMcf/d, 1,100 wells, 1.5 Bcfe/well 8 rig program, expanding PL & facilities for 15 rigs Net potential 4.7 Tcfe 900 Bcfe proved, 1.5 Bcfe type well GIP 83 Bcfe/section EOG 64,000 net acres 110 MMcf/d, 550 wells 7 rig/170 wells 2006 300 Bcfe exploration potential Questar 110 MMcf/d, 700 wells 2,450 potential locations 840 @ 1 Bcfe type well 450 Green River oil 1,160 Mancos/Dakota deep gas Dominion 80 MMcf/d, 400 wells 530 Bcfe proved, 1,500-2,000 locations Gasco 74,000 net acres 18 MMcf/d, 48 wells 3 rig program, 1,500 locations 76.7 Bcfe proved, 1.5-3.5 Bcfe type well THX 100% THX Partial Questar Kerr McGee/ EOG Dominion MAK- J Retamco Gasco Barrett Del Rio/Orion Wind River/Barrett Royale CDX Barrett EnCana Operators in Greater Natural Buttes Source: Web sites of noted companies & IHS Data as of Jan. 2006

THX Position: Uinta Basin Region Project Start: July 2003 2006 Capex: $60 MM 2005 Reserves: 8 Bcfe Net Upside Potential: 800 Bcfe Production: 6.8 MMcfe/d gross 3.8 MMcfe/d net Acreage: 214,455 gross 106,220 net WI: 50% to 100% Partners: Enduring & Elk Wells Drilled: 79 53 connected to sales 18 pending completion 8 P&A Current Rigs: 4 ('06 = 90 well program) Data as of May 2006 '06 Locations, North Area '07 Locations, North Area THX/ER Completed Wells W/O Completion APD Locations Built Developing Significant Leasehold to Exploit THX/Elk AMI THX/Enduring AMI

Project Start: August 2004 2006 Capex: $29 MM 2005 Reserves: 19 Bcfe Net Upside Potential: 450 Bcfe Production: 4.3 MMcfe/d gross 2.8 MMcfe/d net Acreage: 442,800 gross 329,130 net 3-D Seismic: 340 sq mi - 4 surveys WI: 75% to 100% Partner: Santos Wells drilled: 154 115 connected to sales 23 pending completion 15 P&A 1 SWD Current Rigs: 2 ('06 = 125 well program) Wauneta Field Ballyneal Field THX Position: Niobrara Gas Project 60 miles THX Acreage 3-D Outline 3-D Outline 3-D Outline Data as of May 2006 Using 3-D Seismic to Direct Development of Gas Resource

Continue three-rig program to develop 400+ wells Upgrade gathering and compression to minimize flow restrictions throughout field Initiate recompletion program Monitor offset operator shale activity Continue exploration on eastern acreage Arkoma Strategy Optimizing and Expanding Core Producing Areas: An "Efficiency" Play

Focused Operations: Arkoma Inventory PUD 82 Prob/Poss 23 Sub-total 105 Potential 300 Total 405 PUD Wells Probable Wells Possible Wells Note: Data as of May 2006

Arkoma Reserve Growth '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 Legacy 55.8 55.7 55.8 79.9 93.2 100.9 93.1 111.3 131.3 151.2 KMG CAGR 12% Source: Netherland Sewell & Assoc.

Completed Dry '00 20 0 '01 31 4 '02 17 3 '03 41 3 '04 56 6 '05 60 1 '06E 83 0 '07E 78 Arkoma Drilling: Active and Successful Note: '06E and '07E as of May 2006

Continue successful three-to-four rig drilling program to drill 400+ wells Patient growth through small acquisitions and block leasing Continue building gathering capacity to match drilling program Optimize life-cycle costs East Texas Strategy Applying Core Competencies and Expanding Asset Base

E. Henderson Area 90-100% WI 6,140 gross/5,525 net acres 29 producing wells 11 MMcfe/d gross 57 identified locations 42 potential locations North Blocker Area 83% WI 4,790 gross/3,990 net acres 7 producing wells 120 Mcfe/d gross 48 identified locations 48 potential locations (40-acre spacing) Willow Springs 76% WI 8,010 gross/6,075 net acres 43 producing wells 4 MMcfe/d gross 43 identified/potential locations Focused Operations: East Texas Note: As of May 2006

Ongoing Financial Strategy Maximize shareholder returns through balanced capital deployment Exploration and development projects Acquisitions Share repurchases Manage financial and other industry specific risks Commodity price volatility Capital intensity Asset/reserve decline Align capital structure with business/financial profile Maintain prudent balance sheet leverage Maintain financial flexibility Access to debt/equity capital markets Ability to respond quickly to growth opportunities

Reserves '00 19.91 '01 19.83 '02 21.04 '03 24.18 '04 26.5 '05 29.65 Reserves '00 126 '01 151 '02 141 '03 198 '04 131 '05 159 Production per Share Production Replacement Reserves per Share Financial Indicators Reserves '00 2.83 '01 2.93 '02 3.32 '03 3.45 '04 4.14 '05 3.94

Like-kind exchanges (LKEs) regarding TX GOM properties are substantially complete LKEs regarding LA GOM properties have yet to be completed Qualified investment vehicle of $314 MM established at closing (May 31) Potential LKE properties to be identified within 45 days of closing (July 15) Complete purchase of LKE properties within 180 days of closing (Nov. 27) Potential tax impact is $87 MM To begin tax savings, must reinvest > $65 MM (tax basis of properties held in 1031 vehicle) Potential tax savings are material and would serve to enhance acquisition returns Example: Without tax savings: $314 MM/114 Bcfe = $2.75 Tax savings: (87) MM* With tax savings: $227 MM/114 Bcfe = $1.99 Acquisitions will need to make sense strategically, operationally, etc. and will have to compete for capital vs. other opportunities, including share repurchases * Actual cash savings may vary depending on company's other (consolidated) tax attributes Potential tax impact (MM$): 1031 proceeds 314 Tax basis-1031 properties (65) Potential gain for FIT purposes 249 Tax rate 35% Potential tax impact $ 87 28% reduction GOM Sales: Potential Tax Impact

2006 & 2007 Guidance Capital Spending (MM$) E&D 53 421 474 466 11% Acquisition(s) -- 22 22 n/a Subtotal 53 443 496 466 Capitalized Interest, G&A and Other 25 24 -4% Total 521 490 Production Total (Bcfe) 16 75 91 89 19% Percent Hedged n/a n/a 81% 12% Average Daily (MMcfe/d) 44 205 249 245 19% 2006 Exit Rate (MMcfe/d) n/a 225 225 n/a Unit Costs ($/Mcfe) LOE 1.04 0.58 0.66 n/a Severance Tax n/a 0.27 0.23 n/a Transportation 0.04 0.14 0.12 n/a DD&A and ARO n/a n/a 2.96 n/a G&A, Net n/a n/a 0.35 n/a Interest Expense, Net n/a n/a 0.30 n/a (1) Assumes unwinding 80,000 MMBtu/d for the period June - December 2006 following the GOM sales. (2) Based on existing 2007 hedge portfolio of 30,000 MMBtu/d. (1) (2) 2006 GOM Onshore % Change 2006 Onshore 2006 Total 2007 Onshore

Quality assets located in prolific U.S. tight-gas basins Favorable industry environment Positioned for growth Inventory of 7,500 wells Net proved & potential of 2.5 Tcfe Strong financial position Plentiful investment opportunities Dedicated management Focused on execution Committed to enhancing shareholder value Reviewing additional strategic alternatives Summary + +

South Texas

Wells Drilled Production CHK 78 122.547 COP 40 119.98 THX 100 98.139 PPP 12 69.92 CVX 5 44.237 DOM 6 38.525 EOG 23 36.335 DVN 7 21.059 South Texas Offset Operators Wells Drilled Production COP 50 212 EOG 52 46 LEW 99 43 KIL 31 36 THX 12 35 ROS 4 29 CVS 6 25 CHK 1 14 Zapata County Webb County Source: IHS Data as of May 2006

South Texas Reserve Growth '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 Legacy 106 127 137 143 164 230 299 315 327 374 KMG Source: Netherland Sewell & Assoc. CAGR 15%

Rincon TCB Lobo 5 94 16 0 7 101 57 27 9 120 100 61 South Texas Well Economics Drill & Complete (MM$) $1.7 $4.6 $2.7 EUR (Bcf) 1.7 1.6 1.5 Net F&D ($/Mcf) $1.33 $3.29 $2.40 Rincon TCB Lobo

Charco: Legacy Asset 1 mi. 0

Drilling & Completion Costs Webb County Lobo Sand Avg. Depth: 8,700' Zapata County Perdido Sand Avg. Depth: 10,500' Zapata County Lobo Sand Avg. Depth: 13,500' Note: '06 YTD as of April 2006 Drilling Costs Completion Costs '02 0.943 0.53 '03 0.99 0.538 '04 0.952 0.569 '05 1.041 0.763 '06 YTD 1.488 0.889 '02 0.994 1.02 '03 1.059 0.897 '04 1.094 0.986 '05 1.46 1.245 '06 YTD 2.164 1.354 '02 0.597 0.45 '03 0.669 0.604 '04 0.698 0.469 '05 0.876 0.739 '06 YTD

Lifting Other '02 0.1 0.15 '03 0.18 0.15 '04 0.2 0.14 '05 0.28 0.19 '06 YTD 0.35 0.23 South Texas LOE Note: '06 YTD as of April 2006

'02: $0.25/Mcfe '03: $0.33/Mcfe '04: $0.33/Mcfe '05: $0.47/Mcfe '06 YTD: $0.58/Mcfe Manpower 0.04 0.03 0.04 0.04 0.05 Compression 0.03 0.05 0.06 0.1 0.1 SWD 0.02 0.02 0.03 0.03 0.03 Well Service 0.04 0.05 0.05 0.02 0.04 Other Lifting 0.01 0.02 0.02 0.1 0.12 Workover 0 0.05 0.02 0.003 0.02 Ad. Val. Taxes 0.09 0.08 0.1 0.16 0.18 Other Non-Lifting 0.01 0.02 0.02 0.02 0.03 South Texas LOE Components Note: '06 YTD as of April 2006

Artificial Lift Case Study Wells Drilled 1/1/2006 227 1/2/2006 109 1/3/2006 250 1/4/2006 231 1/5/2006 384 1/6/2006 453 1/7/2006 509 1/8/2006 440 1/9/2006 397 1/10/2006 523 1/11/2006 457 1/12/2006 402 1/13/2006 394 1/14/2006 382 1/15/2006 355 1/16/2006 560 1/17/2006 461 1/18/2006 345 1/19/2006 270 1/20/2006 420 1/21/2006 335 1/22/2006 256 1/23/2006 438 1/24/2006 654 1/25/2006 644 1/26/2006 1207 1/27/2006 1164 1/28/2006 919 1/29/2006 720 1/30/2006 515 1/31/2006 632 2/1/2006 836 2/2/2006 704 2/3/2006 758 2/4/2006 719 2/5/2006 747 2/6/2006 788 2/7/2006 790 2/8/2006 839 2/9/2006 510 2/10/2006 392 2/11/2006 367 2/12/2006 425 2/13/2006 504 2/14/2006 682 2/15/2006 695 2/16/2006 405 2/17/2006 789 2/18/2006 1016 2/19/2006 859 2/20/2006 574 2/21/2006 757 2/22/2006 628 2/23/2006 563 2/24/2006 382 2/25/2006 335 2/26/2006 494 2/27/2006 436 2/28/2006 393 3/1/2006 460 3/2/2006 349 3/3/2006 274 3/4/2006 432 3/5/2006 447 3/6/2006 338 3/7/2006 643 3/8/2006 925 3/9/2006 1525 3/10/2006 1759 3/11/2006 1770 3/12/2006 1879 3/13/2006 1703 3/14/2006 1518 3/15/2006 1469 3/16/2006 1340 3/17/2006 1288 3/18/2006 1442 3/19/2006 1490 3/20/2006 1575 3/21/2006 1536 3/22/2006 800 3/23/2006 750 3/24/2006 732 3/25/2006 557 3/26/2006 548 3/27/2006 1672 3/28/2006 1611 3/29/2006 1453 3/30/2006 979 3/31/2006 522 4/1/2006 1318 4/2/2006 900 4/3/2006 555 4/4/2006 986 4/5/2006 1120 4/6/2006 901 4/7/2006 700 4/8/2006 851 4/9/2006 872 1 well 7 wells Plunger Lift Installation at Charco Field Improves Production from Mature Wells

Actual Projection 9/1/2005 335 9/2/2005 326 9/3/2005 329 9/4/2005 314 9/5/2005 303 9/6/2005 305 9/7/2005 304 9/8/2005 304 9/9/2005 305 9/10/2005 307 9/11/2005 307 9/12/2005 305 9/13/2005 322 9/14/2005 562 9/15/2005 759 9/16/2005 731 9/17/2005 668 9/18/2005 640 9/19/2005 631 9/20/2005 637 9/21/2005 643 9/22/2005 618 9/23/2005 620 9/24/2005 606 9/25/2005 606 9/26/2005 628 9/27/2005 616 9/28/2005 606 9/29/2005 603 9/30/2005 599 10/1/2005 595 10/2/2005 620 10/3/2005 561 10/4/2005 600 10/5/2005 587 10/6/2005 561 10/7/2005 562 10/8/2005 571 10/9/2005 576 10/10/2005 566 10/11/2005 565 10/12/2005 565 10/13/2005 555 10/14/2005 560 10/15/2005 558 10/16/2005 557 10/17/2005 561 10/18/2005 566 10/19/2005 552 10/20/2005 551 10/21/2005 542 10/22/2005 540 10/23/2005 532 532 10/24/2005 533 531 10/25/2005 535 531 10/26/2005 530 531 10/27/2005 531 531 10/28/2005 525 530 10/29/2005 527 530 10/30/2005 527 529 10/31/2005 533 529 11/1/2005 529 529 11/2/2005 531 529 11/3/2005 529 528 11/4/2005 530 528 11/5/2005 530 527 11/6/2005 494 527 11/7/2005 509 526 11/8/2005 523 526 11/9/2005 516 526 11/10/2005 516 526 11/11/2005 517 525 11/12/2005 519 525 11/13/2005 520 524 11/14/2005 516 524 11/15/2005 511 524 11/16/2005 515 524 11/17/2005 514 523 11/18/2005 511 523 11/19/2005 511 522 11/20/2005 516 522 11/21/2005 498 522 11/22/2005 857 522 11/23/2005 1444 521 11/24/2005 1477 521 11/25/2005 1368 520 11/26/2005 1410 520 11/27/2005 1338 520 11/28/2005 1272 520 11/29/2005 1330 519 11/30/2005 1218 519 12/1/2005 1226 518 12/2/2005 1145 518 12/3/2005 1176 517 12/4/2005 1179 517 12/5/2005 1167 517 12/6/2005 1158 517 12/7/2005 1127 516 12/8/2005 1101 516 Performed three coiled tubing cleanouts, one slickline bailing and two extended pressure build-ups at Charco Field Spent less than $175,000 total Payout in less than one month Production Enhancement: Operating Expertise Delivers

Production Downtime: Continuous Operating Improvements Operating Expertise and Efficiencies Minimize Production Downtime

Days Avg. '02 Avg. '03 Avg. '04 Avg. '05 Avg. '06 (60 days) 1 1249 1477 1751.672997 1755.78761 1207.01125 2 1877 2210 1705.993831 2978.263756 2080.930833 3 1561 2228 2003.909455 3307.617796 2252.502083 4 1582 2550 1911.128536 3273.921361 1699.432083 5 1331 2745 1717.46673 3164.172552 1438.521739 6 1585 2651 1611.649162 2996.232927 1680.847391 7 1873 2565 2076.416004 3177.480873 2419.945 8 2499 2719 2422.645203 3165.660417 2368.412273 9 2728 2919 2388.516335 3220.654002 2571.853182 10 2592 2950 2485.250231 3130.176619 2363.094762 11 2166 2953 2543.059543 3359.798163 2695.610476 12 2293 3073 2333.46482 3474.137931 3063.5445 13 2383 2971 2433.754266 3561.672414 3103.419 14 2536 2842 2355.240635 3538.086207 2822.539474 15 2638 2484 2360.870888 3703.603448 2489.715556 16 2624 2643 2197.298597 3750.344828 2756.095 17 2458 2750 2338.536914 3475.103448 2837.011667 18 2732 2848 2447.802567 3522.706897 2779.158889 19 2624 2924 2491.007948 3527.655172 2881.047778 20 2739 2797 2478.350789 3380.310345 2647.235882 21 2856 2640 2438.653009 3375.482759 3052.376471 22 2916 2759 2403.890623 3448.241379 3112.528824 23 2891 2443 2305.059156 3477.37931 2953.398824 24 2706 2649 2298.356567 3453.327586 2769.471176 25 2671 2658 2427.072664 3297.413793 2645.704706 26 2702 2616 2365.606497 3196.015172 2739.381176 27 2571 2793 2328.653068 3130.154655 2791.787647 28 2670 2813 2321.361121 3127.534483 2840.715294 29 2653 2836 2339.977338 3084.876207 2821.357222 30 2664 2661 2378.135589 3003.733966 2749.768824 31 2603 2852 1973.23456 2947.551207 2776.044118 32 2570 2975 2137.311926 3049.701724 2580.819412 33 2616 2872 2180.772914 3017.309483 2617.9975 34 2499 2792 2203.81988 2997.83431 2564.1125 35 2523 2786 2209.279446 3060.641724 2754.28125 36 2621 2790 2243.389071 2996.183966 2851.490625 37 2474 2864 2145.833941 2827.694655 2865.424 38 2582 2856 2214.993937 2822.618621 2662.492 39 2545 2766 2200.686291 2763.82569 2647.898667 40 2372 2697 2019.713995 2674.588103 2420.688667 41 2420 2604 2079.4099 2738.617586 2606.635333 42 2464 2540 2033.659204 2730.865172 2510.118571 43 2421 2591 2102.208876 2604.228448 2442.704286 44 2486 2518 2071.605163 2582.783621 2428.764286 45 2493 2534 1953.87933 2566.204655 2389.134286 46 2304 2704 1823.786628 2558.685345 2357.843571 47 2388 2528 1916.644526 2476.568103 2376.714286 48 2316 2540 1942.418346 2454.646034 2125.928571 49 2334 2529 1879.054224 2405.539483 2112.928571 50 2368 2496 1872.054324 2449.291034 2290.428571 51 2255 2465 1906.640637 2399.736207 2179 52 2298 2367 1672.540237 2398.618966 2284.142857 53 2287 2332 1749.211648 2389.212931 2180.285714 54 2235 2407 1700.09307 2271.829828 2258.230769 55 2177 2390 1664.0474 2142.068276 2180.307692 56 2273 2199 1705.686304 2187.117759 2330.923077 57 2210 2423 1605.431898 2217.4 2531.916667 58 2192 2600 1527.263334 2258.711379 2469.333333 59 2180 2701 1542.991446 2168.463448 1629.090909 60 2219 2566 1533.860217 2135.824828 1989.545455 61 2134 2537 1351.267732 2020.860172 62 2130 2285 1402.522768 2035.562241 63 1971 2289 1540.568071 2079.951897 64 2100 2539 1630.216254 2101.468276 65 2093 2545 1590.582789 2022.066379 66 2166 2504 1625.092346 2005.363276 67 1982 2409 1467.956086 1997.152069 68 1845 2392 1430.051738 1941.63069 69 1910 2236 1419.858551 1918.19569 70 1838 2427 1433.247044 1926.894138 71 1819 2433 1381.850371 1867.636034 72 1825 2389 1287.985673 1861.03569 73 1746 2407 1359.113188 1815.038276 74 1800 2359 1320.255273 1829.472586 75 1756 2406 1448.94949 1792.122069 76 1715 2145 1479.085257 1743.246897 77 1686 2150 1437.447227 1700.051034 78 1767 2192 1379.655668 1740.602759 79 1646 2192 1353.061015 1711.278621 80 1704 2132 1434.901086 1703.68931 81 1659 2218 1500.457875 1641.694828 82 1700 2283 1354.789475 1667.836552 83 1702 2315 1519.041712 1629.579828 84 1714 2210 1434.487427 1660.502759 85 1664 2268 1405.476289 1646.639828 86 1691 2159 1353.780617 1584.924828 87 1417 2185 1371.690214 1586.823276 88 1642 2128 1223.252318 1645.227241 89 1618 2253 1150.471901 1594.721724 90 1714 2226 1333.767183 1557.708448 91 1571 2188 1300.223614 1533.981207 92 1537 2142 1312.490577 1490.277759 93 1493 2050 1310.961949 1478.611207 94 1647 2129 1303.481024 1560.809828 95 1418 2082 1197.34309 1489.398448 96 1425 2042 1171.802982 1469.616552 97 1558 1972 1219.832987 1448.892931 98 1565 1972 1148.938001 1320.66569 99 1640 2001 1262.644128 1277.641207 Mature, But Still Delivering: Charco Field

Expanding South Texas into the Vicksburg Play: Rincon Field PUD Wells

Expanding South Texas into the Vicksburg Play: TCB Field - Vicksburg 8,800' Structure

Expanding South Texas into the Vicksburg Play: TCB Field - Vicksburg 11,000' Structure

Development Potential in the Vicksburg Play: TCB Field

Vicksburg Area LOE Rincon TCB San Carlos Vaq. Ranch Total Lifting 1.29 1.46 0.87 2.32 1.59 Other 0 1.29 0 0.04 0.34 Note: Data as of April 2006

Rocky Mountains

Altamont Bluebell Natural Buttes Drunkards Wash Helper Red Wash Monument Butte Wonsits Valley Antelope Creek Horseshoe Bend Walker Hollow 8-Mile Flat N Brundage Canyon Castlegate Rock House Oil Springs Ashley Valley Duchense Cedar Rim Clay Basin Coyote Basin Peters Point Flat Rock Brennan Bottom White River Kenned y Wash Gypsum Hills Pariett e Bench Gordon Creek Main Canyon Fence Canyon Uteland Butte Soldier Creek Buck Canyon Devils Playground 9 Mile Canyon Love Seep Ridge Pine Springs Stone Cabin Uinta Basin Utah

Uinta Basin Well Performance Comparison 0 100 200 300 400 Avg. Gross Production per Well (Mcfe/d) 0 200 400 600 800 1,000 1,200 Active Wells STR NFX DOM Gasco THX PXD KMG EOG Mcfe/d Active Wells Source: IHS Data as of Jan. 2006

THX/Enduring AMI AMI 138,735 G/99,825 N Acres 50% WI 77 wells drilled, 45 THX/32 ER 52 wells connected, 37 THX/15 ER 17 wells w/o completion, 2 THX/15 ER 8 wells P&A, 6 THX/2 ER 3 wells drilling 17 locations built 60 APD Note: Data as of May 2006 THX/ER Completed Wells W/O Completion APD Locations Built

Reducing Line Pressure is Key to Production Increases

Enduring JV: Production Plan Note: '06E as of May 15, 2006 Estimate

THX Production Profiles Mcf/d Months 1 10 100 1,000 10,000 0 20 40 60 80 100 120 140 160 180 200 15% - 430 MMcf 8% - 500 MMcf 4% - 530 MMcf KMG - 1.5 Bcf Rock House #11-31 Nov '04 #1 Nov '04 #2 Sept '05 Oct '05 May '06 #1 May '06 #2 May '06 #3

Uinta Potential 5.4 Tcfe Gross in Place 1.6 Tcfe Gross Recoverable Upside 800 Bcfe Net Recoverable 2.8 Tcfe Net in Place

Low Today Target 5 -15 -10 7 -6 6 22 9 14 28 61 Uinta Basin Well Economics Drill & Complete (MM$) $1.5 $1.5 $1.5 Net F&D ($/Mcf) $2.50 $3.75 $4.36 .75 Bcf EUR .50 Bcf EUR .43 Bcf EUR Price Deducts Basis: -$1.75 Gathering: -$0.60 Total: -$2.35

THX/Elk Joint Venture Ouray Park 22,005 G/17,670 N Acres 47% WI 2 wells drilled 1 well connected 1 well w/o completion 1 well drilling Note: Data as of May 2006 N. Horseshoe 10,585 G/10,320 N Acres 47% WI 12 APD THX 100% 43,130 G/43,130 N Acres 13 APD Note: Data as of May 2006 '06 Drilling Locations '07 Drilling Locations

Elk Ouray Joint Venture Wasatch Tests Nielsen #3-22 Cum. 11,000 bbls since 12/05 Currently recompleting additional Wasatch pay Potential EUR >150 Mbbls Rogers #13-16 Est. 60' pay Mesaverde Test - spud 6/2/06 Wall #13-17: 14,500', $4.7 MM drill & complete 100% THX Acreage Wasatch/Mesaverde Tests PTD of 5,000'-10,000' Drill & complete of $1.0-$1.7 MM First well in 2006 N. Horseshoe Bend JV Wasatch Tests PTD of 10,500' Drill & complete of $2.0 MM Elk 50% WI partner First test in 2006 Northern Uinta Basin Acreage

Permits: Key to Future 28 Companies - 1,612 Permits - All Depths The top six companies account for 88% of the permits in the Uinta Basin 0 50 100 150 200 250 300 350 400 DOM Gasco THX KMG NFX PXD STR EOG Slate Permits Source: IHS Data as of Jan. 2006

Geologic Exploration of northern acreage through drilling 5-7 wells in next 12 months Continue to improve delineation of gas sweet spots Investigate deeper potential below Mesa Verde Production and Reserves Fracture stimulation optimization Build infrastructure to maintain stable and low gathering pressure throughout acreage Costs Additional scale decrease in LOE per well allows optimization of infrastructure and creates more competitive service contracts Expand take-out capacity: ability to send gas east or west within 18 months Lower water handling costs: four SWD applications have been accepted by the EPA Regulatory Four Environmental Assessments in progress Uinta Basin Upside

Niobrara Production & Compression Wauneta Field (Republican 3-D) 59 wells drilled, 49 completed, 9 P&A, 1 SWD 800 Mcf/d, 1,300 bwpd, 35 psi line pressure Optimizing pumping unit performance Ballyneal Field (Wauneta 3-D) Generated 335 locations to date 95 wells drilled, 66 completed, 23 WOC, 6 P&A 4,200 Mcf/d, 1,300 bwpd, 75 psi line pressure Constructing SWD facility Compression expansion 6/06, 9/06, 11/06 Note: Data as of May 2006

Niobrara Well Costs Drilling Turnkey 0.23 Fracturing 0.27 Wireline 0.06 Rig 0.01 Production Cement 0.02 Casing/Tubing 0.15 Facility/Flowline 0.09 Permit/Damages 0.02 Labor 0.05 Location 0.05 Other 0.05 Average Well Costs '06 YTD: $222,000 per well Note: '06 YTD as of May 2006

Niobrara 2006 LOE & Production Monthly Field Average $63,000 Other $9,148 Labor $20,186 SWD $11,274 Compression $22,572 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% LOE Component ($/Month) 0 20 40 60 80 100 Aug-05 Sep-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06 Apr-06 Production (MMcfe/Mo) 0 1 2 3 4 5 LOE ($/Mcfe) Production LOE Wauneta Area First Sales - August 2005 Ballyneal Area First Sales - January 2006 Note: Data as of April 2006

Low 5 15 7 38 9 61 Niobrara Well Economics Drill & Complete (MM$) $.23 Net F&D ($/Mcf) $.88 Niobrara EUR (Bcf) .30 Price Deducts Basis: -$1.40 Gathering: -$0.60 Total: -$2.00 Niobrara Type Curve: Long-life Reserves

Continue 125+ well drilling program/year to delineate fault blocks set up by new 3-D Add 2+ rigs in '07 to develop proved acreage Expand 3-D seismic in 100+ square mile increments to cover all prospective acreage Add gathering and compression to match drilling activity Optimize water handling to lower costs and provide maximum production from each well Niobrara Upside Strategy

Whitney Canyon, WY: Development Current Acreage: 5,160 gross & 3,870 net (BP farm-in) WI: 37% - 75% Net Unrisked Upside: 3 - 5 Bcfe per well, 6 wells 320-acre spacing Projected Spud: 3Q06 Est. Drilling & Completion Costs: $2.8 MM dry-hole costs and $0.8 MM completion costs PTD 13,800' Status: Permitting

Whitney Canyon, WY: Gas Potential First Location Phosphoria and Weber reservoirs Phosphoria Structure Map Note: Data as of April 2006

Arkoma Basin

Focused Operations: Arkoma Chismville Area

Focused Operations: Arkoma Inventory PUD 82 Prob/Poss 23 Sub-total 105 Potential 300 Total 405 PUD Wells Probable Wells Possible Wells Note: Data as of May 2006

Arkoma Offset Operators Wells Drilled Production XTO 1178 158 Stephens 658 98 THX 332 75 SWN 134 73 Merit 101 19 Hanna 157 17 CHK 116 13.7 Sedina 151 13 Reliance 20 11.8 Ross 47 10.7 Source: IHS Data as of Jan. 2006

Arkoma Production - 10 20 30 40 50 60 70 80 1/03 3/03 5/03 7/03 9/03 11/03 1/04 3/04 5/04 7/04 9/04 11/04 1/05 3/05 5/05 7/05 9/05 11/05 1/06 3/06 5/06 Gross Production (MMcf/d) - 1 2 3 4 5 6 7 8 IP (MMcf/d) & Rig Count Arkansas Operated IP Rate Rig Count Compression Adds Line Loops

0% 2% 4% 6% 8% 10% 12% 14% 16% Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Downtime Linear (Downtime) Production Downtime: Continuous Operating Improvements Operating Expertise and Efficiencies Minimize Production Downtime

Arkoma Reserve Growth '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 Legacy 55.8 55.7 55.8 79.9 93.2 100.9 93.1 111.3 131.3 151.2 KMG CAGR 12% Source: Netherland Sewell & Assoc.

Completed Dry '00 20 0 '01 31 4 '02 17 3 '03 41 3 '04 56 6 '05 60 1 '06E 83 0 '07E 78 Arkoma Drilling: Active and Successful Note: '06E and '07E as of May 2006

HIGH MID 5 40 23 7 77 50 9 117 79 Arkansas Well Economics Price Deducts Basis: -$0.80 Gathering: -$0.20 Total: -$1.00 Drill & Complete (MM$) $.75 $.75 Net F&D ($/Mcf) $1.13 $1.64 .80 Bcf EUR .55 Bcf EUR

Lifting Production Reserves Acres Other '96 8.874 16 203 99 56.483 '97 51.2 30 219 127 0 '98 42.788 43 291 126 79.183 '99 43 44 305 117 0 '00 62.865 44 332 110 0 '01 95.734 43 385 126 69.01 '02 0.11 20 452 156 0.04 '03 0.12 23 508 417 0.08 '04 0.09 38 502 619 0.02 '05 0.09 43 616.224 970 0.03 '06 YTD 0.11 40 0.08 '07E 460 107 Arkoma LOE Note: '06 YTD as of May 2006

Drilling Mob/Demob 0.03 Location 0.04 Daywork 0.23 Stimulation 0.18 Drilling Svcs. 0.2 Completion Svcs. 0.16 Casing & Tubing 0.16 Arkoma Drilling & Completion Costs Average Well Costs '06 YTD: $783,000 per well Drilling Completion '03 248 203 '04 292 278 '05 308 292 '06 YTD 439 344 Note: '06 YTD as of May 2006

East Texas

Straight Directional 5 7 0 7 26 11 9 46 23 East Texas Well Economics Drill & Complete (MM$) $1.5 $2.1 EUR (Bcf) 1.0 1.0 Net F&D ($/Mcf) $1.97 $2.76 Vertical Directional Price Deducts Basis: -$0.62 Gathering: -$0.40 Total: -$1.02

Lifting Production Reserves Acres Other '96 8.874 16 203 99 56.483 '97 51.2 30 219 127 0 '98 42.788 43 291 126 79.183 '99 43 44 305 117 0 '00 62.865 44 332 110 0 '01 95.734 43 385 126 69.01 '02 0.82 1.856 452 156 0.23 '03 0.83 1.56 508 417 0.2 '04 0.86 1.908 502 619 0.22 '05 0.79 4.9 616.224 970 0.15 '06 YTD 0.68 10.1 0.13 '07E 460 107 East Texas LOE Note: '06 YTD as of May 2006

East Henderson Field Note: As of May 2006 0

East Henderson Production 0 2 4 6 8 10 12 14 3/05 4/05 5/05 6/05 7/05 8/05 9/05 10/05 11/05 12/05 1/06 2/06 3/06 4/06 5/06 6/06 7/06 Gross MMcf/d Rig Release to First Sales 0 10 20 30 1 3 5 7 9 11 13 15 17 19 21 23 25 Well Count Days

East Henderson Drilling Performance 0 100 200 300 400 500 0 5 10 15 20 25 30 Wells Rotating Hours 0 10 20 30 40 50 60 70 80 90 100 Daily Drilling Cost (M$) Rotating Hours Drilling Cost

Drilling Rig Costs 0.28 Stimulation 0.17 Tubulars/Pipelines 0.14 Equipment 0.11 Location 0.05 Fuel/Chemicals 0.05 Labor/Services 0.09 Other 0.11 East Henderson Well Costs Average Well Costs '06 YTD: $1.8 MM per well Note: '06 YTD as of May 2006

East Henderson Normalized Production 1 Bcf Well

Blocker Field Note: As of May 2006

Willow Springs Field Note: As of May 2006

Financial Summary

Onshore Offshore '03 508 247 '04 502 291 '05 616 245 Onshore Offshore '03 63 45 '04 68 56 '05 69 45 '06E 75 16 '07E 89 0 Reserves '03 12.79 '04 16.72 '05 16.17 1Q06 4.26 Reserves '03 4.2 '04 5.44 '05 3.62 1Q06 4.26 Historical Performance EPS CFPS Production Reserves 108 124 114 Note: '06E and '07E as of May 2006. 2005 Production excludes approx. 10.6 Bcfe of production that was shut-in and deferred as a result of Hurricanes Katrina and Rita. 756 793 861 91 89

E&D Acquisitions '03 285 175 '04 367 150 '05 546 197 Hedged Gas Price EBITDA Unhedged Gas Price '03 4.55 416 4.48 '04 5.17 539 5.78 '05 5.21 485 7.71 1Q06 28 Prod. Cost G&A, Int. & Other DD&A/ARO Hedge Loss Net Income Before Tax (Margin) '03 0.68 0.11 1.87 0.63 1.91 '04 0.64 0.33 2.18 0.57 2.09 '05 0.86 0.48 2.63 2.31 1.47 1Q06 1.09 0.57 3.03 1.49 1.63 Historical Performance Capex EBITDA vs. Price Unit Margin Note: EBITDA is Income from Operations + DDA/ARO + Other (Income) Expense. See Non-GAAP reconciliation. Note: Capex includes expense for E&D and acquisition activities. Excludes property dispositions and expense for corporate items. (IT, FF&E, etc.) 460 517 743 5.20 5.81 7.75 7.81 "All-in" Hedged Unhedged '03 4.55 0.68 '04 5.17 0.64 '05 5.21 2.5 1Q06 6.02 1.61 Realized Gas Price 5.23 5.78 7.71 7.63 Note: The "all-in" hedge price includes (i) gains/losses realized on hedge contracts settled during the period and (ii) unrealized gains/losses. 416 539 485

Hedge Summary Swaps Volume (MMBtu/d) 80,000 30,000 --- --- Wtd. Avg. Price ($/MMBtu) 5.30 5.89 --- --- Costless Collars Volume (MMBtu/d) 180,000 190,000 30,000 20,000 Wtd. Avg. Floor Price ($/MMBtu) 4.83 5.79 5.00 5.00 Wtd. Avg. Ceiling Price ($/MMBtu) 6.43 7.08 6.60 5.72 Total Hedges Volume (MMBtu/d) 260,000 220,000 30,000 20,000 Wtd. Avg. Floor Price ($/MMBtu) 4.98 5.81 5.00 5.00 Wtd. Avg. Ceiling Price ($/MMBtu) 6.09 6.92 6.60 5.72 Total Production (Mcfe/d) 313,000 249,000 245,000 n/a Total Hedges as % of Total Production* 80% 85% 12% n/a 2005 2008E 2007E 2006E Note: Data as of June 30, 2006. * Assumes conversion factor of 1.04 MMBtu/Mcfe.

Debt (MM$) LTD - Revolver 249.0 (216.0) 48.7 61.6 143.3 LTD - Senior Sub. Notes 175.0 --- --- --- 175.0 Total Debt 424.0 (216.0) 48.7 61.6 318.3 Equity (MM$) 899.4 --- --- (61.6) 837.8 Total Capitalization (MM$) 1,323.4 (216.0) 48.7 --- 1,156.1 Proved Reserve Roll-forward (Bcfe) 774.2 604.3 Total Debt/Capitalization 32% 28% Total Debt/Proved Mcfe ($/Mcfe) 0.55 0.53 Net Debt /Capitalization 30% 0% Net Debt /Proved Mcfe ($/Mcfe) 0.51 0.00 (1) Includes entries/adjustments for TX GOM sale (closed 3/31/06). (2) Includes $4.4 MM in transaction costs, $14.3 MM in hedge unwind, and expected $30 MM TEPI NPI payment. (3) Reflects purchase of 1,177,000 THX shares as of 6/30/06 at an average price of $52.39 per share (4% of shares outstanding). (4) Estimated reserves = YE05 reserves (860.8 Bcfe) less TX GOM disposition (58.5 Bcfe) and 1Q06 production (28.1 Bcfe). (5) Estimated reserves = YE05 reserves (860.8 Bcfe) less TX GOM disposition (58.5 Bcfe) and 1Q06 production (28.1 Bcfe) plus ETX acquisition (16.2 Bcfe) less LA GOM disposition (186.1 Bcfe). Excludes reserve additions related to 1Q06 E&D capex. (6) As of 3/31/06, total debt less $32.0 MM restricted cash held in 1031 Trust. (7) Proforma 1Q06, total debt less $324.9 MM restricted cash held in 1031 Trust. Proforma Capital Structure Actual 1Q06 Proforma 1Q06 Closing Adjustments Post- Closing Adjustments Share Repurchases LA GOM Sale (1) (2) (3) (4) (5) (6&7) (6&7)

Reconciliation of Non - GAAP Financial Measures EBITDA represents net income (loss) before interest expense, income tax expense (benefit) and depreciation, depletion and amortization. EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. EBITDA is widely used by investors, bankers and rating agencies to value, compare and rate companies. EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. EBITDA is reconciled to net income as follows: Reconciliation of Non-GAAP Financial Measures (MM$): 2003 2004 2005 EBITDA 415.5 538.9 485.2 Less Interest, net 8.3 9.4 16.5 Income taxes 72.2 96.6 62.9 Depreciation, depletion and amortization 201.2 270.1 300.6 Cumulative effect of change in accounting principle 2.8 - - Net income: 131.0 162.8 105.2

For a detailed glossary, please see the Glossary of Oil and Gas Terms set forth on page G-1 of our Annual Report on Form 10-K, as amended, for the year ended December 31, 2005. Additional terms used herein, but not defined in the Glossary, are set forth below: - AMI Area of mutual interest. - APD Application for permit to drill. - CAGR Compounded annual growth rate. - EUR Estimated ultimate recovery. - FIT Federal income tax. - GIP Gas in place. - IHS Independent petroleum information source. - P&A Plug and abandon. - PRB Probable recovery of hydrocarbons. - PTD Potential total depth. - PUD Proved undeveloped reserves. - ROR Rate of return. - R/P Reserves-to-production ratio. - RRC Texas Railroad Commission. - SWD Saltwater disposal well. - TCF Trillion cubic feet. - W/O Waiting on completion (WOC). Glossary of Terms