T HE H OUSTON E XPLORATION C OMPANY IPAA April 20, 2004 THX

Houston Exploration Profile  North American natural gas producer  Founded in 1986; public in 1996; traded on NYSE  Current market capitalization of +$1.3 billion ‑ Enterprise value of +$1.6 billion  2003 Highlights: ‑ Proved reserves:755 Bcfe (67% onshore, 33% offshore) ‑ Daily production:295 MMcfe/d (93% natural gas) ‑ Net income:$131 MM ($4.20/sh) ‑ Closed two acquisitions:TEPI and EnerVest ‑ YE debt-to-cap:29%

THX Business Strategy Manage volatility through hedging program Replace 100+% of production through low-risk exploitation Provide significant upside through offshore exploration Maintain flexibility through fiscal responsibility and conservative debt levels Pursue selective acquisitions that provide attractive ROR Build Shareholder Value Focus on core areas with high operational control and working interest Focus on the Basics

THX Growth with Financial Discipline Debt:Cap62%56%38%30%30%29%

THX Operating Areas South Texas: 140 MMcfe/d Proved Reserves:315 Bcfe (42%) South Texas: 140 MMcfe/d Proved Reserves:315 Bcfe (42%) Gulf of Mexico: 122 MMcfe/d Proved Reserves:247 Bcfe (33%) Gulf of Mexico: 122 MMcfe/d Proved Reserves:247 Bcfe (33%) Arkoma: 23 MMcfe/d Proved Reserves:111 Bcfe (15%) Arkoma: 23 MMcfe/d Proved Reserves:111 Bcfe (15%) Total 2003 Avg. Production:295 MMcfe/d

THX Balanced Portfolio High Low Risk Production Impact Offshore Deep Shelf Expl. Offshore Deep Shelf Expl. Replace Production Predictable Upside Significant Upside WV Arkansas S. Texas Offshore Dev. Rockies

THX Capital Program 2004E Capex $315 MM 52% Onshore 41% Offshore 7% Other 2003 Capex $460 MM* 36% Onshore 59% Offshore 5% Other * Includes acquisition capex of $149 MM for TEPI & $28 MM for EnerVest

THX 2004 Onshore Plans  South Texas ‑ Continue 6 rig program ‑ Add opportunities to maintain production and reserves  Arkoma ‑ Implement 80-acre spacing ‑ 2 to 3 rig program  Rockies ‑ 1+ rig(s) all year, test 3+ basins and add reserves ‑ Begin to “narrow” Rockies focus  Appalachia ‑ Assimilate West Virginia acquisition ‑ Drill 2 wells & make plans for undeveloped acreage  South Texas ‑ Continue 6 rig program ‑ Add opportunities to maintain production and reserves  Arkoma ‑ Implement 80-acre spacing ‑ 2 to 3 rig program  Rockies ‑ 1+ rig(s) all year, test 3+ basins and add reserves ‑ Begin to “narrow” Rockies focus  Appalachia ‑ Assimilate West Virginia acquisition ‑ Drill 2 wells & make plans for undeveloped acreage

THX Onshore: Why We’re Here Source: PGC 2002 Data Anadarko <15M’ TX Gulf Coast Appalachian Uinta/Piceance Powder River Permian <15M’ Green River Anadarko >15M’ LA Gulf Coast San Juan Onshore Basins Have 74% of Near-Term US Gas Potential Top 10 Producing Basins THX

2004 capex$113 MM Active rigs6 Well cost$1.1 - $2.5 MM Reserves/well1 – 2 Bcf Avg. well depth8,000’ – 12,500’ Producing sandsWilcox/Lobo 3-D seismic1,200 sq. miles 2003 Stats: Production 140 MMcfe/d Operated wells476 Net acres 65, capex$113 MM Active rigs6 Well cost$1.1 - $2.5 MM Reserves/well1 – 2 Bcf Avg. well depth8,000’ – 12,500’ Producing sandsWilcox/Lobo 3-D seismic1,200 sq. miles 2003 Stats: Production 140 MMcfe/d Operated wells476 Net acres 65,000 South Texas Operations THX Acreage 3D Seismic Area

THX Arkoma Basin Operations 2004 capex$23 MM Active rigs2-3 Well cost$450 - $650 M Reserves/well.5 – 1.0 Bcf Avg. well depth5,500’ Producing sandAtoka 2003 Stats: Production 23 MMcfe/d Operated wells170 Net acres 35, capex$23 MM Active rigs2-3 Well cost$450 - $650 M Reserves/well.5 – 1.0 Bcf Avg. well depth5,500’ Producing sandAtoka 2003 Stats: Production 23 MMcfe/d Operated wells170 Net acres 35,000

THX Rocky Mountain Operations Why the Rockies?  Large gas potential  Low F&D ($1/Mcfe or less)  Similar targets to other THX onshore operations  High level of management experience in area What we’ve done so far:  200,000 acres in five states  2004 capex of $20 MM  12 wells planned for 2004  Already success at Uinta Basin Why the Rockies?  Large gas potential  Low F&D ($1/Mcfe or less)  Similar targets to other THX onshore operations  High level of management experience in area What we’ve done so far:  200,000 acres in five states  2004 capex of $20 MM  12 wells planned for 2004  Already success at Uinta Basin Montana Wyoming Utah N. Dakota S. Dakota Uinta Basin Green River Basin Big Horn Basin Williston Basin

THX 2004 Offshore Plans  Add reserves and production from the TEPI acquisition ‑ Exploration and development opportunities  Exploit the potential of the deep-shelf prospects ‑ Drill first THX operated deep-shelf test  Apply appropriate technology to reduce the risk and uncertainty for exploration  Develop new, operated, high-impact prospects ‑ Participate in offshore lease sales  Add reserves and production from the TEPI acquisition ‑ Exploration and development opportunities  Exploit the potential of the deep-shelf prospects ‑ Drill first THX operated deep-shelf test  Apply appropriate technology to reduce the risk and uncertainty for exploration  Develop new, operated, high-impact prospects ‑ Participate in offshore lease sales

THX 2004 Drilling Program THX Lease Exploration Well TEPI Acquisition Lease Development Well EC % WI WC 96 40% WI ST % WI GA % WI HI % WI BA % WI EI Wells 100% WI HI A283 3 Wells 70% WI WC Wells 100% WI WC 77 MARG A 25% WI WC 77 25% WI EC 33 50% WI 2004 Capex = $128 MM YE03 Gulf Position Blocks:127 (69 Dev) THX Operated:32 Platforms:80

THX High Island A-283 A-283 B-1 A-4 ST2 A-2 1 A-3 A-5 A-1 Proposed A-6 Proposed A-4 ST3 Proposed A-7 Proposed A-3 ST THX A-1 ST L-9 L-7A L New Well Production at HI A-283: 15 MMcf/d

THX THX’s Gulf of Mexico Potential Total Unrisked Potential 2,587 Bcfe Total Unrisked Potential 2,587 Bcfe

THX 2003 Costs Are Competitive Full-Cycle Average $3.37 Source: Company reports

THX High Cash Margins Yield Profits $4.32 $3.37 $2.40 $4.57 Total Cash Costs

THX NYMEX Contract Price Avg.($/MMBtu) VolumeEffectiveEffective MMBtu/dFloorCeiling 1Q04100,000$4.70none 2Q04 – 4Q04100,000$4.41$6.91 Calendar ‘04100,000$3.75$5.05 Calendar ‘04 40,000$4.96n/a Calendar ‘05 50,000$4.77n/a Calendar ‘05150,000$4.50$5.69 NYMEX Contract Price Avg.($/MMBtu) VolumeEffectiveEffective MMBtu/dFloorCeiling 1Q04100,000$4.70none 2Q04 – 4Q04100,000$4.41$6.91 Calendar ‘04100,000$3.75$5.05 Calendar ‘04 40,000$4.96n/a Calendar ‘05 50,000$4.77n/a Calendar ‘05150,000$4.50$5.69 Hedged Production Gas Hedges

THX Proven Growth Record 13% CAGR Reserves Production 14% CAGR

THX The THX “Distinctions”  Geographically focused: 89% of reserves in 3 core areas  Natural gas emphasis: 94% of reserves  Strong track record of production and reserve growth  Operational control: Operates 85% of properties / 75% avg. W.I.  Low cost producer: $1.12/Mcfe cash costs in 2003  Drilling inventory: Current three-year prospect inventory  Accomplished acquirer of assets  Financial discipline / balance sheet strength

T HE H OUSTON E XPLORATION C OMPANY 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 anticipated dates of first production, 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 report and risks and uncertainties inherent in the Company’s business set forth in the filings of the Company with the Securities and Exchange Commission, including without limitation, the Company’s most recent Annual Report on Form 10-K. These risks include, among others, oil and gas price volatility, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of proved reserves and in projections of future rates of production and timing of development expenditures, environmental risks, regulatory changes, general economic conditions, and the actions or inactions of third party operators. The Company does not undertake any obligation to update any forward looking statements contained in this report. 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 term “exploration 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. 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 anticipated dates of first production, 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 report and risks and uncertainties inherent in the Company’s business set forth in the filings of the Company with the Securities and Exchange Commission, including without limitation, the Company’s most recent Annual Report on Form 10-K. These risks include, among others, oil and gas price volatility, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of proved reserves and in projections of future rates of production and timing of development expenditures, environmental risks, regulatory changes, general economic conditions, and the actions or inactions of third party operators. The Company does not undertake any obligation to update any forward looking statements contained in this report. 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 term “exploration 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.