Production Company Update June 29, 2004

Cautionary Statement Regarding Forward-looking Statements This presentation includes forward-looking statements and projections, made in reliance on the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The company has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed in this presentation, including, without limitation, the ability to implement and achieve our objectives in the long-range plan; any developments arising from additional reviews of the reserve revisions performed internally or by independent counsel to the Audit Committee; the extent and time periods involved in the restatement of our prior years' financial results whether or not related to reserve revisions; the ongoing discussions with the SEC regarding the company's plan for restatement of prior years' financial results; the potential impact of the restatement of financial results on our access to capital (including borrowings under credit arrangements); further changes in reserve estimates based upon internal and third party reserve analyses; uncertainties and potential consequences associated with the outcome of governmental investigations; outcome of litigation including shareholder derivative and class actions related to reserve revisions and restatements; consequences arising from the delay in filing of our periodic reports including the exercise of remedies by the company's lenders under certain financing arrangements and if such remedies were to be exercised, the company's potential inability to identify and obtain alternate sources of financing and the existence of cross- acceleration provisions in various financing agreements; uncertainties associated with exploration and production activities; actions by the credit rating agencies; the successful close of our financing transactions; our ability to successfully exit the energy trading business; our ability to close our announced asset sales on a timely basis; changes in commodity prices for oil, natural gas, and power; inability to realize anticipated synergies and cost savings associated with restructurings and divestitures on a timely basis; general economic and weather conditions in geographic regions or markets served by El Paso Corporation and its affiliates, or where operations of the company and its affiliates are located; the uncertainties associated with governmental regulation; political and currency risks associated with international operations of the company and its affiliates; difficulty in integration of the operations of previously acquired companies, competition, and other factors described in the company's (and its affiliates') Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither the company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. The company assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward- looking statements made by the company, whether as a result of new information, future events, or otherwise.

Agenda Introduction Philosophy and Reorganization Status Report Financial Summary Conclusions

Introduction

Production Stabilization Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Rigs 19 18 17 17 15 12 16 18 20 19 18 16 2004 Rig Activity (by month)* # of Rigs 19 18 17 17 15 12 16 18 20 19 18 16 Activity increase is a leading indicator *Includes gross operated rigs; July through December are estimates Assessment Re-activation

What You Will Hear Stabilized production Improved mix Capex generates good returns Reserves will grow Emphasis on improved efficiency Free cash flow positive Continue high-grading portfolio

Philosophy and Reorganization

Business Plan Capital discipline Continual monitoring of base business Cost control Rigorous reserve booking process Regional autonomy Pay for performance

Capital Discipline Monitor all investment options Consistent risk and economic methodology Balanced allocation of capital Stringent post-mortem evaluation Continual portfolio review

Focus on the "Base Business" Artificial lift Production efficiency Mature property analysis Accelerate recompletions and workovers

Reducing Unit Costs: The Way Forward Review of sub-economic properties Increase production through enhancement projects Optimization of high-cost components

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 Peer 18 Peer 19 0.56 0.58 0.6 0.63 0.65 0.660000000130967 0.66 0.68 0.69 0.7 0.7 0.7 0.71 0.72 0.75 0.83 0.87 0.88 0.9 0.95 0.99 1.03 Cost Leadership: Production Costs* Peer Group Comparison Summary Data Mean: $0.76 Median: $0.71 25th Percentile: $0.66 *Production costs include lease operating expenses plus production related taxes. All information is for the year ended 12/31/03 (except for EP 2004 and EP target). EP statistics excluded from summary data ~$0.65 EP Target EP 2004 EP 2003 $0.70+/- $0.56

Enhanced Controls on Reserve Booking Outside Reservoir Engineering Firm Reserves and Evaluation Group Regional Operations Board of Directors Corporate Reserves Committee In restructuring our reserve booking process, we implemented the following changes: Centralized reserves and evaluation group to estimate and report reserves Regional operations will supply data Corporate reserves committee to oversee reserve bookings and interface with the Board of Directors The Audit Committee will engage an outside reservoir engineering firm to complete year-end audit ~ ~

Regional Autonomy Geographically focused operations Fit-for-purpose organization Total accountability Leverage high-quality professional staff

Drilling Construction Land Operations Marketing Restructured Production Organization: Integrated Business GOM/South Louisiana Texas Gulf Coast Onshore International E&P Services Acquisitions/Divestitures Technologies Reservoir Engineering Procurement Marketing Exploration Development/ Exploitation

Production Reorganization: Streamlined Decision Making Officers Directors Managers Other Foreign nationals 19 26 94 790 77 1,006 1/1/2004 6/15/2004* % Reduction 11 23 60 715 24 833 8 3 34 75 53 173 42 12 36 9 69 17 *Includes employees that support other non-regulated operations

Pay for Performance New incentive system in 2005 Drilling success Achieving plan targets Peer reviews

Status Report

Scorecard Conclude rationalization Fit competencies to basins Return to cost leadership Production costs G&A Improve capital efficiency Improve predictability Pay for performance Substantially complete Accomplished in reorganization Plan established; progress being made Near-term Goals Instituting standardized risk analysis Implement during 2005 Status

Domestic Region Statistics: January 1, 2004 Texas Gulf Coast 624.3 Bcfe proved reserves 5.5 R/P ratio* $1,667 MM pre-tax PV-10% Gulf of Mexico 440.1 Bcfe proved reserves 4.3 R/P ratio* $1,422 MM pre-tax PV-10% Onshore: Coalbed Methane 836.2 Bcfe proved reserves 17.9 R/P ratio* $1,440 MM pre-tax PV-10% Onshore: Arklatex 363.0 Bcfe proved reserves 12.5 R/P ratio* $929 MM pre-tax PV-10% Onshore: Rockies 87.8 Bcfe proved reserves 13.7 R/P ratio* $92 MM pre-tax PV-10% *Based on 2Q 2004 production annualized Reserves by Area Pre-tax PV-10% Total = $5.6 Billion Texas Gulf Coast 30% Gulf of Mexico 26% Onshore 44% Total = 2.4 Tcfe Texas Gulf Coast 26% Gulf of Mexico 19% Onshore 55%

PUD Reserves GOM/South Louisiana Texas Gulf Coast Onshore Total Domestic International Total Proved Undeveloped PUD/ Total Proved (%) Total Proved 94 99 508 701 187 888 440 624 1,287 2,351 284 2,635 21 16 39 30 66 34 Reserves (as of January 1, 2004) Division Proved Developed 346 526 778 1,650 97 1,747 Reserve Category (Bcfe)

PUD Reserves by Division GOM Texas Gulf Coast International Onshore East 11 11 21 57 GOM/South Louisiana Texas Gulf Coast International 21% Onshore 57% 11% 11% Total = 888 Bcfe

2004 Estimated Capital Expenditures Texas Gulf Coast International Onshore GOM/S. Lousiana East 24 5 36 35 Total = $850 MM Texas Gulf Coast 24% International Onshore 36% GOM 35% 5% Long-range Plan (December 15, 2003) Total = $850 MM Texas Gulf Coast International Onshore GOM/S. Lousiana Acquistions East 20 9 31 30 10 Texas Gulf Coast 20% International 9% Onshore 31% GOM 30% Current Estimate (June 29, 2004) Acquisitions 10%

Capital Allocation/Portfolio Summary Reward Risk Low Medium High CBM and Rockies Arklatex GOM S. LA South Texas International 2003 Allocation = 12% 2004 Allocation = 28%* 2005 Allocation = 28%* 2003 Allocation = 55% 2004 Allocation = 40%* 2005 Allocation = 44%* 2003 Allocation = 33% 2004 Allocation = 32%* 2005 Allocation = 28%* *Estimate Note: Excludes corporate and other general capital items

*Estimate Improving Production Mix Onshore International Gulf of Mexico Texas Gulf Coast 2004 Production 28 5 34 33 Onshore International Gulf of Mexico Texas Gulf Coast 2005 Production 33 8 27 32 28% 5% 34% 33% 33% 32% 27% 8% 2004 Production* 2005 Production* Onshore Gulf of Mexico International Texas Gulf Coast Onshore Texas Gulf Coast Gulf of Mexico International

Finding Costs and Reserve Growth Estimated capital expenditures ($ MM) Estimated finding cost ($/Mcfe) Estimated reserve growth (%)* 2005 850 $1.90-$2.25 2%-4% 2004 850 $2.25-$2.75 0%-2% *Includes acquisitions and sales

GOM/South Louisiana 266 federal blocks in GOM 31 state leases in GOM (14 LA; 17 TX) 3D seismic inventory of 6,567 GOM blocks and 3,600 sq. miles onshore in South Louisiana

GOM/South Louisiana Strengths and Weaknesses Strengths Acreage and seismic position High rate of return Technical expertise Weaknesses Overweighting of high-risk/high-exposure investments Steep decline Inventory of high-cost, marginal properties

GOM/South Louisiana Business Strategy Focus on core property profitability Detailed "team" evaluations of existing properties Eliminate marginal properties Balanced allocation of capital to full-risk spectrum Exploitation of low-risk opportunities Reduced interest Expand focus beyond the "Deep Shelf" Expand opportunity inventory Evaluate more 3rd party prospects Consider property acquisitions with undeveloped, lower risk opportunities

2004 GOM/South Louisiana Capital Program Abandonment Leasing Seismic Drill & Equip Recompl & Artif Lift GOM / SLA 5 7 8 63 17 Total Capital = $215 MM Drilling 63% Seismic 8% Leasing Abandonment 5% Production Capital 7% 17%

GOM Highlights Year-to-date drilling results Eugene Island 371: Two successful wells on production Eugene Island 364: Installed platform on time and on budget. A-1 completion in progress Ewing Bank 1003 A-2 (Prince): Successful sidetrack encountered updip pay S. Marsh Island 223 #221 (JB Mountain #3): TA'd - evaluating sidetrack State Lease 340 #2 (Mound Point): TA'd - evaluating deepening $30 MM recompletion program in progress

GOM/South Louisiana Future Opportunities Remaining 2004 drilling program: Three exploration/six development wells with net risked mean reserves of 39 Bcfe Current identified prospect inventory for 2005 forward: 29 exploration prospects with net risked mean reserves of 139 Bcfe 15 development wells with net risked mean reserves of 55 Bcfe Exploration potential reflects 20%-60% working interest

2004-2005 GOM/South Louisiana Production Profile MMcfe/d March to May drop primarily due to three fields: ST 212 - Water encroachment WD 137 - Water encroachment SMI 223 - Scale restriction

GOM Marginal Field Revitalization March 2004: Ten fields identified as providing no operating cash income Initiated operational review and implemented remediation plan June 2004: Nine of the ten fields are generating positive operating cash income Total investment of $6.2 MM to date; will payout in four months Production increased to 12.6 MMcfe/d May 2004 operating cash income of $2.4 MM Phase 1 Marginal Field Initiative

GOM Conventional Shelf Development 372 371 370 Cris S TB 2 TB 10 TB1 TA 1 TB 10 A-11 A-12 A-6 A-1 A-3 A-2 A-5 A-4 EI 364/365 Development A11 well: 1st Prod 4-04 (700 Bbl/d) A12 well: 1st Prod 5-04 (9 MMcfe/d) A1 well: Completing Remaining 2004: Three additional wells 2005: Two additional wells Eugene Island 364/371 Development

Deep Shelf Strategy Continue commitment to the Deep Shelf 30% of 2004 GOM capital Utilize experience Planning and evaluation Cost prediction Risk assessment Manage exploration risk Reduced working interest Exposure to more opportunities

West Cameron Cris R Trend X 218 Acres El Paso WC46/47 WC54 WC45 WC44 Newfield WC77 (Drilling) 55 Bcf Cris R Discoveries Emerging Cris R AVO Trend Current Drilling West Cameron Block 46/47 West Cameron Block 62 2004 Deep Shelf Opportunity Hydrocarbon indicators have demonstrated reliability in the trend providing Ps > 80% Prolific Deep Shelf opportunity demonstrated in W. CAM 46/47 with cumulative production of 55 Bcf from two wells CUM: 55 Bcf EL PASO WC62 Cris R

South Louisiana: Catapult South Louisiana: Catapult South Louisiana: Catapult LAKE CHARLES LAYFAYETTE Catapult

South Louisiana: Catapult Catapult Project: 3,600 sq. miles onshore 3D data Phase I area under evaluation Phase II to be delivered 3Q 2004 Survey complete 1Q 2005 Three unsuccessful exploratory prospects drilled to date South Florence: Sand present/no seal Lake Misere: Sands were tight Blackfish Lake: Sands present/no seal Four prospects under lease and ten under evaluation Two wells planned for 2nd half 2004

GOM/South Louisiana: Summary Arrest decline with approximately $200 MM annual capex More balanced program Consistent risk methodology Focus on base properties Recompletions and workovers Eliminate marginal properties Continue exploration with reduced interest

Texas Gulf Coast 300,000 acres (net) 2D seismic inventory of 54,300 miles 3D seismic inventory of 5,480 sq. miles

TGC Strengths and Weaknesses Strengths Large acreage and seismic holdings Extensive infrastructure Technical knowledge of basin Low operating cost area Potential for giant producers (>50 MMcf/d) Weaknesses Steep initial decline rates Target reservoirs are deep and high temperature Well costs are high Deep targets have poor seismic resolution Reservoir quality is difficult to predict

TGC Business Strategy Maximize value from existing property base More focus on well surveillance and production costs Four full-time engineers on well surveillance Initiated programs to reduce production costs Compression, chemical, SWD and contract labor Re-examining remaining development opportunities Implement more disciplined exploration program Obtain industry partners Focused leasing efforts

2004 TGC Capital Program Production Capital Leasing Seismic Drilling East 18 6 2 76 Production Capital Leasing 2% Seismic Drilling Total Capital = $150 MM 16% 6% 76%

2004 TGC Highlights Year-to-date drilling results Drilled 19 total wells (84% success rate) One well currently drilling One well currently completing Building locations to add four drilling rigs in July 2004 Plan to drill 18 wells in the 2nd half of 2004 Eight exploratory, ten development/exploitation Eight wells are not expected to commence production until early 2005 $26 MM production enhancement program in progress Seismic reprocessing of the "Beast" survey

TGC Exploratory Inventory Eight exploratory prospects to be drilled in 2004 Seven of eight will be operated by EP Total depths range from 16,200' to 22,000' Net risked mean reserves for the program are 31.5 Bcfe Partners anticipated on seven of the eight prospects Expected average WI BCP of 54% Expected average WI ACP of 70% Expect to drill 11-12 exploratory prospects during 2005 Currently evaluating 2005 inventory of 25 prospects/leads

2004-2005 TGC Production Profile MMcfe/d

TGC Production Enhancement Projects 1/1/2003 2/1/2003 3/1/2003 4/1/2003 5/1/2003 6/1/2003 7/1/2003 8/1/2003 9/1/2003 10/1/2003 11/1/2003 12/1/2003 1/1/2004 2/1/2004 3/1/2004 4/1/2004 MMCFE/D 84.472 82.337 73.167 66.804 60.23 56.384 52.706 50.045 45.771 42.518 41.805 35.969 33.995 34.702 35.117 35.401 1 Qtr Forecast MMCFE/D 39.957 38.428 37.352 36.517 BASE DECLINE 82.6 75.735 69.618 64.151 59.246 54.83 50.848 47.245 43.975 41.004 38.29 35.813 33.5521 31.471 29.557 27.798 821 728 653 610 Base Decline Production Uplift 7.6 MMcfe/d 84 projects on wells completed before 2003 resulting in an incremental gross 3.2 Bcfe for 2004 Total cost $3.9 MM gross 42 plungers 16 gas lift 26 misc. 105 additional projects identified Note: Production history and decline is only from 84 completed projects

2004 Drilling Cost Goals TGC Drilling Cost Trend < 12,000' 12,001' - 15,000' 15,001'-17,000' > 17,001' 01/01/02-4/30/03 87.99 133.27 181.32 207.74 05/01/03-03/31/04 99.57 133.89 171.98 186.41 2004 Goal 87.99 127.19 163.38 177.09 86 Wells 23 Wells 49 Wells 22 Wells 50 Wells 15 Wells 39 Wells 10 Wells More deliberate drilling yields cost improvements 5 Wells 14 Wells 8 Wells 8 Wells

North Hidalgo 3D Merge The Beast Data Merge Seismic Reprocessing for AVO Analysis >1,500 sq. miles (12 merged surveys) PSTM with AVO volumes Total cost of $2 MM Delivery date July 2004 TGC: Applying New Technology to Core Areas Jeffress Samano N. Monte Christo Santa Fe Ranch

TGC Big Holler Prospect Fitzhenry Heirs #2, TD 14,830' Flowing to sales at 4.4 MMcf/d Lavaca County Fitzhenry Heirs #1 (100% interest) Initial rate: 52 MMcf/d and 151 Bbl/d 90 Day Cum: 3.87 Bcf and 7,450 Bbl 50 MMcf/d Fitzhenry Heirs #2

TGC Summary Production rates stabilized Good inventory of investment opportunities Managing existing assets to maximize value Significant industry interest in potential joint ventures

Rockies Arkoma Arklatex Black Warrior Raton Onshore 1.9 MM acres (net) 2D seismic inventory of 26,500 miles 3D seismic inventory of 1,147 sq. miles

Onshore Strengths and Weaknesses Strengths Large undeveloped inventory Low to medium-risk investments Significant infrastructure Shallow decline rates Technical expertise Weaknesses Mature conventional properties

2004 Onshore Capital Program Acq & Divest Abandonment Leasing Seismic Drill & Equip Recompl & Artif Lift Onshore 28 1.46 12.1 2.7 189.3 20 Total Capital = $260 MM Note: Includes CBM, Arklatex and Rockies Drilling 74% Seismic 1% Leasing Abandonment 1% Production Capital 11% Acquisitions 5% 8%

2004-2005 Onshore Production Profile MMcfe/d

Coal Bed Methane Business Strategy Maximize cost and recovery efficiencies through long-range development planning Focused development of leasehold position 909,000 net acres; 19% developed Fully leverage technical expertise Focus on core areas Structure organization and systems to ensure utilization of "best practices"

Coal Bed Methane Highlights Net production has increased 10% from 121 MMcf/d (January 2004) to 133 MMcf/d (current) Shift development strategy from reserve growth to value maximization: Minimizes infrastructure costs Shortens turnaround time to first production Improves production efficiency through optimized de-watering

Coal Bed Methane Highlights Focus on optimizing existing properties Artificial lift efficiency improvements Production engineers located within the fields dedicated solely to production enhancement Expanding applications of technology and best practices Raton horizontal pilot tests underway Pump off controllers Consolidated drilling/completion technical staff

CBM Technology Application: Horizontal Drilling Arkoma Basin Arkoma Basin Drilling Program Results Program Mix Avg. Cost 1st Yr Avg. 2002: 8% horizontal $186k / well 50 Mcf/d / well 2003: 50% horizontal $311k / well 140 Mcf/d / well 2004: 100% horizontal $450k / well 270 Mcf/d / well Mcf/d per well 2002 2003 2004

Coal Bed Methane: Raton Recovery Efficiency Improvements Horizontal drilling and completion Three horizontal wells drilled and producing with encouraging initial productivity results Additional tests planned Longer evaluation period required for determination of potential recovery impact Formation re-stimulation Five wells re-fractured with a sustained average production increase of 175% per well

CBM Technology Application: Pump Off Controllers Vermejo Park Ranch D#49 Production increase associated with optimizing fluid levels and maximizing runtime Expense reduction due to: Manpower optimization Power consumption Pump life and repair costs Mcf/d & Bw/d POC installed

White Oak Creek Acquisition Increased interest in the White Oak Creek field of Alabama's Black Warrior Basin from 75% to 85% (June 2004) Acquisition increases interest in a core area and in a profitable field with significant remaining development potential Predictable long-life gas reserves Approximately 84% of proved reserves are PDP Hedged gas production for three years Purchase Price ($MM) Proved Reserves (Bcfe) RAC Costs ($/Mcfe)1 Purchase Price/ 2004E EBITDA (x) Daily Production ($/Mcfed) 22.9 11.7 1.95 3.7 6,300 1RAC= Reserve Acquisition Cost (defined as purchase price divided by proved reserves) Black Warrior Basin

Coal Bed Methane: Summary Large inventory of undeveloped acreage Arkoma: 942 locations Black Warrior: 765 locations Raton: 589 locations Changing business approach Applying technology Improved development planning

Arklatex Business Strategy Be a cost leader within the basin Focus on regional trends as well as existing property exploitation Participate in 3rd party joint ventures Presence in the acquisition market Expand basin visibility Optimize the existing properties Personnel dedicated solely to production enhancement Expand utilization and pursue improved performance of artificial lift applications

Arklatex Highlights 28 of 46 development wells planned for 2004 have been drilled Production remains stable with $40 MM annual development capital spending 78 MMcfe/d (January 2004) 78 MMcfe/d (MTD Avg - June 2004) Two exploratory wells planned for 2nd half 2004 with net risked mean reserves of 10 Bcfe

Arklatex: Production Enhancement Results Base Decline Production Uplift Note: Production history is only from the 58 projects completed to date 58 projects completed YTD resulting in an incremental 1.1 Bcfe for 2004 39 plungers 6 compressors 13 miscellaneous projects 65 additional projects identified Base Impact North Louisiana Gross Mcf/d

Arklatex: Lifting Cost Improvement $ Well Well Count Arklatex OPEX History

Rockies Business Strategy Maintain experienced Rockies staff and basin presence Near-term focus on Altamont-Bluebell Fully evaluate field potential Initiated workover, recompletion, artificial lift enhancement, and selective development drilling Increase utilization of available plant capacity Evaluate basin expansion opportunities Drill remaining exploratory inventory in 2004 Seek participation opportunities in 3rd party joint ventures Expand basin visibility

Rockies: Altamont/Bluebell 3 billion Bbl estimated original oil in place 363 MMBoe produced to date El Paso Production 450,000 gross acres 400 operated wells 2,000 net Boe/d (June 2004) 2004 program 2 development wells 14 recompletions Altamont - Bluebell

Arklatex/Rockies: Summary Focus on cost and recovery efficiencies Profitably execute existing property development Regional trend analysis Evaluate and pursue expansion opportunities Increase understanding and quantification of Altamont-Bluebell potential

International Operations Indonesia Hungary Australia Turkey Brazil Nova Scotia

BTB Pipeline Potiguar Basin Santos Basin Northeast Pipeline International: Brazil Camamu Basin 1.1 MM acres (net) 2D seismic inventory of 54,683 km 3D seismic inventory of 7,052 sq. km Espirito Santos Basin

Brazil Strengths and Weaknesses Strengths Ownership in 14 concessions Strong technical knowledge Sizeable exploration portfolio Oil exposure Weaknesses Limited amount of PDP reserves Single-country concentration

2004 International Capital Program (Excluding Canada) Acquisitions Leasing Seismic Drilling East 61 8 19 23 Seismic 17% Drilling 20% Total Capital = $110 MM Leasing 7% Acquisitions 56% 95% allocated to Brazil

International 2004-2005 Production MMcfe/d Note: Includes 100% of UnoPaso volumes as of July 29, 2004

Brazilian Highlights Acquiring UnoPaso for $61 MM+ Luana discovery of 80 Bcfe (probable) Located in Santos Basin Currently negotiating GSA Several oil discoveries (with associated gas) in Camamu Basin

UnoPaso Acquisition Acquiring remaining 50% interest in UnoPaso partnership. Assets of partnership include the Pescada-Arabaiana field area offshore Brazil Six production concessions (production of 27 MMcfe/d net to 50% interest) and one exploration concession Petrobras operated (65% interest) Reserve and volume upside exists Growing demand for natural gas in Brazil's northeastern segment Significant exploration/exploitation potential on acreage Hedged oil production for three years Purchase Price1 ($MM) Proved Reserves (Bcfe) RAC2 ($/Mcfe) Purchase Price/ 2004E EBITDA (x) Daily Production ($/Mcfed) 61.0 70.5 0.87 3.3 2,200 1Does not include potential additional cash consideration (up to $19 MM) in the event certain gas price and/or gas volume targets are met 2RAC = Reserve Acquisition Cost (defined as purchase price divided by proved reserves)

2004 International Exploration: Espirito Santo Basin, Brazil BM-ES-5 B-ES-100 14 km

International Summary Portfolio rationalized Large Brazilian acreage and seismic position Acquiring UnoPaso for $61 MM 163 Bcfe net risked mean reserves for the exploration program

Financial Summary

Production by Region 4Q 2003 1Q 2004 2Q 2004 Texas Gulf Coast 333 308 309 Onshore 213 224 222 GOM 406 369 282 International 4 5 1 MMcfe/d 9561 9061 8143 Sequential Decline (MMcfe/d) 50 92 1Excludes production from Canadian properties divested during 1Q 2004 2Includes 20 MMcfe/d of positive prior period adjustments 3Through June 15, 2004 2 (QTD)3

2004 Production Forecast Year-to-date production (167 days)* Plus: Remaining 2004 production rate (199 days) Plus: Acquisition production (156 days) Total production (Bcfe) 2004 Production (MMcfe/d) (MMcfe/d) 149 145-163 8-9 302-321 897 730-820 53-56 NM Period Production 407 396-444 22-24 825-875 *Through June 15, 2004

2004-2005 Estimated Capital Expenditures GOM/South Louisiana Texas Gulf Coast Onshore International Other/Corporate Total 2005 $215 150 260 130 95 $850 2004 Division $ Millions $200 200 275 75 100 $850

Operational and Financial Review Production (MMcfe/d) Production costs ($/Mcfe)1 Other taxes ($/Mcfe) General and administrative expenses ($/Mcfe) Total cash expenses2 1Q 2004 1,003 $0.67 0.02 0.25 $0.94 4Q 2003 956 $0.60 0.02 0.43 $1.05 2004 Forecast 825-875 $ 0.66-$0.76 0.01-0.02 0.48-0.52 $1.15-$1.30 2005 Forecast 825-875 $0.61-$0.70 0.01-0.02 0.43-0.48 $1.05-$1.20 1Production costs include lease operating expenses plus production related taxes 2Cash expenses equal total operating expenses less DD&A and ceiling test and other charges, which have not been determined

Henry Hub price ($/MMBtu) Realized gas price ($/MMBtu) Revenues3 ($ MM) Cash expenses2 Cash generation capacity Capital expenditures ($ MM) Cash Generating Capacity Daily volume (MMcfe/d)1 Annual volume (Bcfe) Cash expenses ($/Mcfe)2 850 310 $1.125 1Assumes production mix is 85% gas, 12% oil and 3% NGLs 2Cash expenses equal total operating expenses less DD&A and ceiling test and other charges, which have not been determined. Rate of $1.125/Mcfe is based on $4.25/MMBtu Henry Hub price 3Excludes the effect of commodity price hedges. Assumes a realized oil price of $23.92/Bbl (based on a WTI price of $24.00/Bbl) and a realized NGL price of $16.39/Bbl Operating Assumptions $4.25 3.93 $1,210 350 860 $850 $5.00 4.68 $1,410 355 1,055 $850 $6.00 5.68 $1,670 365 1,305 $850

Long-Range Plan Comparison: Key Milestones Volumes (MMcfe/d) DD&A rate ($/Mcfe) Cash costs ($/Mcfe) 2005 900-1,000 $1.75-$1.90 $0.80-$1.00 2004 Volumes (MMcfe/d) DD&A rate ($/Mcfe) Cash costs ($/Mcfe) 850-950 $1.85-$2.10 $0.95-$1.10 Long-Range Plan 2005 825-875 TBD $1.05-$1.20 2004 825-875 TBD $1.15-$1.30 June 29 Plan Update

Long-Range Plan Comparison: Key Milestones EP Cash Generation Impact vs. Plan1 Production (MMcfe/d) 825 875 $4.25 Natural Gas Price2 ($/MMBtu) 900 1,000 $5.00 $6.00 1Cash expenses equal total operating expenses less DD&A and ceiling test and other charges, which have not been determined. Assumes cash costs of $1.125/Mcfe (at $4.25/MMBtu gas price) and capital expenditures of $850 MM 2Excludes the effect of commodity price hedges 180 (70 ) (255 ) 255 (5 ) (205 ) 295 25 (180 ) 445 150 (75 )

Conclusions

2004-2005 Production Profile* MMcfe/d *Assumes mid-point of 2004 and 2005 production guidance

Key Take-aways Stabilized production Improved mix Capex generates good returns Reserves will grow Emphasis on improved efficiency Free cash flow positive Continue high-grading portfolio

Production Company Update June 29, 2004

Appendix EPPH Operating and Financial Information

EPPH Region Statistics: January 1, 2004 Gulf of Mexico 256.8 Bcfe proved reserves 3.8 R/P ratio* $958 MM pre-tax PV-10% Onshore: Coalbed Methane 835.5 Bcfe proved reserves 18.0 R/P ratio* $1,439 MM pre-tax PV-10% Reserves by Area Pre-tax PV-10% Total = 1.5 Tcfe Texas Gulf Coast 5% Gulf of Mexico 17% Onshore 78% Onshore: Arklatex 362.0 Bcfe proved reserves 12.5 R/P ratio* $926 MM pre-tax PV-10% Total = $3.6 Billion Texas Gulf Coast 7% Gulf of Mexico 27% Onshore 66% Texas Gulf Coast 87.0 Bcfe proved reserves 4.9 R/P ratio* $254 MM pre-tax PV-10% *Based on 2Q production annualized

Production by Region 4Q 2003 1Q 2004 2Q 2004 Texas Gulf Coast 67 60 48 Onshore 201 203 207 GOM 246 242 186 MMcfe/d 5141 5051 4412 Sequential Decline (MMcfe/d) 9 64 1Excludes prior period adjustments 2Through June 15, 2004 (QTD)

EPPH Operational and Financial Review Production (MMcfe/d) Production costs2 ($/Mcfe) Other taxes ($/Mcfe) General and administrative expenses ($/Mcfe) Total cash expenses3 Capital expenditures ($ MM) 1Q 2004 496 1 $0.61 - 0.20 $0.81 $183 4Q 2003 2004 Forecast 549 1 $0.47 0.04 0.38 $0.89 $113 440-460 $0.60-$0.63 0.01-0.02 0.45-0.48 $1.06-$1.13 $410 1Includes prior period adjustments 2Production costs include lease operating expenses plus production related taxes 3Cash expenses equal total operating expenses less DD&A and ceiling test and other charges, which have not been determined