THE HOUSTON EXPLORATION COMPANY

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THE HOUSTON EXPLORATION COMPANY
THE HOUSTON EXPLORATION COMPANY
THX
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%
Business Strategy
THX
Focus on the Basics
Focus on core
areas with high
operational control
and working interest
Replace 100+% of
production through
low-risk exploitation
Manage volatility
through hedging
program
Build Shareholder
Value
Maintain
flexibility through
fiscal responsibility
and conservative
debt levels
Pursue selective
acquisitions that
provide attractive ROR
Provide significant
upside through
offshore exploration
Growth with Financial Discipline
THX
Reserves
0.90
Debt/Total Proved
0.80
600
0.70
400
0.60
0.50
200
0.40
0
Debt:Cap
0.30
1998
1999
2000
2001
2002
2003
62%
56%
38%
30%
30%
29%
Debt: $/Mcfe
Reserves: Bcfe
800
THX
Operating Areas
Total 2003 Avg. Production:
295 MMcfe/d
Arkoma:
23 MMcfe/d
Proved Reserves: 111 Bcfe (15%)
South Texas:
140 MMcfe/d
Proved Reserves: 315 Bcfe (42%)
Gulf of Mexico:
122 MMcfe/d
Proved Reserves: 247 Bcfe (33%)
Balanced Portfolio
THX
High
Offshore Deep
Shelf Expl.
Risk
Significant Upside
Rockies
Predictable Upside
Offshore Dev.
Replace Production
S. Texas
Arkansas
Low
WV
Production Impact
Capital Program
THX
2003 Capex
$460 MM*
5%
Other
59%
Offshore
2004E Capex
$315 MM
7%
Other
36%
Onshore
* Includes acquisition capex
of $149 MM for TEPI
& $28 MM for EnerVest
41%
Offshore
52%
Onshore
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
Onshore: Why We’re Here
THX
Onshore Basins Have 74% of Near-Term US Gas Potential
50
THX
40
30
Top 10 Producing Basins
Source: PGC 2002 Data
San Juan
Anadarko
>15M’
Green River
Permian <15M’
Powder River
Uinta/Piceance
0
Appalachian
10
TX Gulf Coast
20
LA Gulf
Coast
Spec.
Poss.
Prob.
Anadarko <15M’
Reserve Potential (Tcf)
THX
THX
South Texas Operations
2004 capex
$113 MM
Active rigs
6
Well cost
$1.1 - $2.5 MM
Reserves/well
1 – 2 Bcf
Avg. well depth
8,000’ – 12,500’
Producing sands
Wilcox/Lobo
3-D seismic
1,200 sq. miles
2003 Stats:
Production
Operated wells
Net acres
THX Acreage
140 MMcfe/d
476
65,000
3D Seismic Area
THX
Arkoma Basin Operations
2004 capex
$23 MM
Active rigs
2-3
Well cost
$450 - $650 M
Reserves/well
.5 – 1.0 Bcf
Avg. well depth
5,500’
Producing sand
Atoka
2003 Stats:
Production
Operated wells
Net acres
23 MMcfe/d
170
35,000
THX
Rocky Mountain Operations
Why the Rockies?
 Large gas potential

Low F&D ($1/Mcfe or less)
Montana

Similar targets to other
THX onshore operations
Big Horn
Basin

Wyoming
Green
River
Basin
Uinta
Basin
Utah

2004 capex of $20 MM

12 wells planned for 2004

Already success at Uinta Basin
N. Dakota
Williston
Basin
S. Dakota
High level of management
experience in area
What we’ve done so far:
 200,000 acres in five states
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
2004 Drilling Program
THX
YE03 Gulf Position
Blocks:
127 (69 Dev)
THX Operated: 32
Platforms:
80
WC 77
MARG A
25% WI
WC 77
25% WI
WC 96
40% WI
GA 191
67% WI
EC 160
BA 399
33% WI
EC 33
50% WI
72% WI
HI 262
50% WI
ST 278
50% WI
HI A283
3 Wells
WC 269
2 Wells
EI 331
2 Wells
100% WI
70% WI
100% WI
2004 Capex = $128 MM
THX Lease
TEPI Acquisition Lease
Development Well
Exploration Well
High Island A-283
THX
2004 New Well Production
at HI A-283: 15 MMcf/d
A-4 ST2
A-1 ST
L-4
A-283
Proposed
A-7
A-5
Proposed
A-4 ST3
A-1
A-3
L-7A
1
Proposed
A-3 ST
Proposed
A-6
THX
A-1 ST
A-2
B-1
L-9
THX
THX’s Gulf of Mexico Potential
247
186
Proved
Probable/Possible
1,405
749
Total Unrisked Potential
2,587 Bcfe
Shallow Exploration
Deep Exploration
2003 Costs Are Competitive
THX
6
5
$/Mcfe
4
Full-Cycle Average $3.37
3
2
1
Total Cash Costs
Source: Company reports
DD&A and Exploration
COG
NBL
MHR
DVN
WRC
TBI
FST
SKE
NFX
SGY
THX
XTO
PPP
EAC
POG
0
THX
High Cash Margins Yield Profits
$5.00
$4.57
$4.32
$/Mcfe
$4.00
$3.00
$3.37
$2.40
3.45
3.31
2.44
$2.00
1.56
$1.00
$0.00
.13
.25
.46
.17
.35
.49
.15
.27
.51
.15
.29
1997
2001
2002
2003
Cash Lifting Cost
G&A
Interest
.68
Cash Flow
Total
Cash
Costs
Hedged Production
2005
2004
THX
Gas Hedges
NYMEX Contract Price
Avg.
($/MMBtu)
VolumeEffective
Effective
MMBtu/d
Floor
Ceiling
1Q04
100,000
$4.70
none
2Q04 – 4Q04
100,000
$4.41
$6.91
Calendar ‘04
100,000
$3.75
$5.05
Calendar ‘04
40,000
$4.96
n/a
Calendar ‘05
50,000
$4.77
n/a
Calendar ‘05
150,000
$4.50
$5.69
Proven Growth Record
THX
Production
Reserves
800
755
108
103
100
650
608
90
600
80
541
562
480
71
Bcfe
Bcfe
63
400
51
337
50
200
0
0
'97
'98
'99
'00
'01
'02
'03 '04E
'97
'98
'99
'00
'01
'02
'03
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
THE HOUSTON EXPLORATION 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.

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