EXHIBIT 99.B          

Long-Range Plan December 2003

Cautionary Statement Regarding Forward-looking Statements This release 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 release, including, without limitation, the ability to implement and achieve our objectives in the long-range plan; the successful implementation of the settlement related to the western energy crisis; 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 divest of certain assets; 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; changes in reserves estimates based upon internal and third party reserve analyses; 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; the uncertainties associated with the outcome of governmental investigations; the outcome of pending litigation including shareholder derivative and class actions; political and currency risks associated with international operations of the company and its affiliates, especially due to the instability in Brazil and economic conditions in Mexico; 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.

Purpose To provide natural gas and related energy products in a safe, efficient, dependable manner

Values Stewardship Integrity Safety Accountability Excellence

How We're Governed 10 of 12 independent directors Separate chairman and CEO positions 5 of 12 new All 5 new directors are upstream oriented Active and committed Board of Directors Board is not staggered No pill Model for modern corporate governance More evolution to come

Near-term Goals Agree on what we will be New executive team Fit for purpose organization Pay for performance Right the production ship Grow the pipelines

The Result in 2006 $500 MM-$725 MM net income, or earnings per share of $.75-$1.10 EBITDA: $3.2 billion-$3.6 billion Annual capex: $1.6 billion-$1.7 billion Total net debt: $15 billion Strong North American natural gas company

Agree On What We Will Be Long term Pipelines: U.S. and Mexico Production: U.S. and Brazil Marketing and physical trading Ownership interest in Enterprise/GTM entity Medium term Power: Asia, Central America/Europe, Brazil, U.S. Telecom: Metro, Lakeside Historical trading portfolio Near term GTM GP interest and units to be sold in Enterprise/GTM transaction Petroleum: Aruba, Eagle Point, terminals Domestic Power: Contracted, some merchant Canadian upstream Indonesian upstream

New Executive Team Human Resources Western Pipelines Production Company General Counsel

Current Organization EPC Holding Company Domestic Production GTM GP Interest Discontinued Operations Pipeline Group Mexico JV Operations Eastern Pipeline Group Western Pipeline Group Southern Natural Gas Production Group Midstream Group El Paso Field Services Southern LNG Refining and Petroleum International Production Brazilian Production Marketing/ Trading Global Networks Merchant Group Domestic Power LNG Contracts International Power

Fit for Purpose Organization EPC Holding Company Production and Processing Marketing and Trading Brazilian Integrated Business EPD/GTM Interest Asian Power Global Networks Domestic, European, and C. America Power Discontinued Operations Mexico JV Operations Eastern Pipelines (TGP, ANR, Great Lakes) Western Pipelines (EPNG, CIG, WIC, Mojave) Southern Pipelines (SNG, 50% Citrus) Long term Medium term Near term Unregulated Businesses Regulated Businesses

Pay for Performance Metrics tied to shareholder value Critically evaluate individual performance Wide incentive bands Equity to top 1,000+- (1.5% annual dilution) We won't get it all right for 2004 (80%)

Right the Production Ship New leadership Touch bottom Lengthen R/P Reduce natural declines Capital discipline and execution Regain credibility

Grow the Pipelines Stable earnings with 2%-5% growth Benefits of footprint Significant scale Supply basin diversity Portfolio effect Fits macro environment well

Midstream Business

Transaction Overview Merger of GulfTerra (GTM) and Enterprise (EPD) creates North America's leading midstream company Complementary assets provide geographic and product diversity and balance Transaction involves 3 principal components: El Paso's sale to EPD of a significant portion of its interests in GTM, as well as certain related gas processing assets Merger of GTM and EPD Joint ownership of the combined MLP's general partner 50% by Enterprise Products Company (EPCO) and 50% by El Paso

Transaction Overview El Paso would receive approximately $1.1 billion cash in exchange for: Sale of a 50% interest in the GTM GP, and subsequent permanent reduction in its incentive distribution to 25% Approximately 14 MM of our 22 MM LP units South Texas gas processing plants associated with GTM's South Texas gathering assets El Paso would receive $425 MM for the GP interest at signing, and will simultaneously pay Goldman Sachs approximately $92 MM and 0.8 MM common units to eliminate its 9.9% GP interest Each GulfTerra LP unit holder will receive 1.81 Newco LP units for every LP unit of GTM previously held

Governance 10-member Board of Directors; El Paso and EPD each select 5, including 3 independents (6 total independents) Current Enterprise Chairman (Dan Duncan) will continue in current role Current Enterprise President, CEO, and Vice Chairman (O.S. (Dub) Andras) will continue as CEO and Vice Chairman GTM CEO (Bob Phillips) to be President and COO

Strategic Transaction Benefits New entity would be the second largest energy MLP with enterprise value of approximately $11 billion and annual EBITDA of approximately $1 billion Creates largest midstream entity with diversified operations and cash flow along natural gas value chain Increases exposure to high growth natural gas supply regions and compliments current assets Expands opportunity set for acquisitions and greenfield development projects Lower cost of capital

Combined Enterprise and GulfTerra Assets Enterprise GulfTerra GulfTerra Texas NGL Enterprise dehydration unit Enterprise gas processing plant Enterprise fractionation plant Enterprise storage facility GulfTerra platform GulfTerra gas processing/treating plant GulfTerra NGL fractionation plant GulfTerra gas storage facility

Conclusion Proposed transaction is positive for El Paso, GTM, and EPD El Paso monetizes significant portion of the value created in GTM; proceeds used for debt reduction Retain significant exposure (13.2 MM LP units plus 50% GP interest) to North America's leading midstream company

Financial Summary

Financial Outlook Methodology 2006 targets reflect completion of restructuring objectives Providing details of our core businesses in 2004 and 2005 Timing of asset sales, refining margins, etc. make forecasts for total company impractical 2004 and 2005 milestones provide clear targets to measure our progress

Our Plan: What We Can Control Our cost structure $150 MM of further reductions or synergies necessary to hit targets First step in process: Corporate restructuring Our operations Pipelines: Returns on capital investment, re-contracting, and rate cases Production: Returns on capital investment, lower costs, and shift to longer reserve life Power: Operating efficiencies and recovery of cash investment Marketing: Efficiently manage production volumes and remaining trading assets Our debt reduction Protect liquidity Liquidation process will be managed for value Recover working capital efficiently

Cost Reduction Update Clean slate process implemented in 2003 $445 MM of cost savings identified Timing dependent on completion of asset sales program 2003 target impact expected to be achieved Next steps Restructure organization consistent with strategy Continue to simplify corporate structure Eliminate activities that cannot be justified in this environment Key focus is that next $150 MM should fall to our bottom line

2006 Core Earnings Assumptions Pipelines 2003E EBIT: $1,335 MM EBIT growth: 2%-5% Production and Processing 1 Bcfe/d production in 2006 $1.65-$1.75/Mcfe DD&A rate $2.45-$2.60/Mcfe total unit costs $4.00-$4.50/MMBtu natural gas price $0.20/MMBtu basis differential International Power 2003E EBIT: $225 MM EBIT growth: 0%-5% Marketing and Trading 2003E EBIT = $(375) MM-$(400) MM Business to be self-supporting Midstream interest GP and LP interest in EPD/GTM Corporate and other Includes hedge costs

2006 Core Earnings and Cash Flow $ Millions, Except Per Share EBITDA DD&A EBIT Interest expense1 Earnings before tax Taxes (35%) Net income Non-cash adjustments DD&A Non-cash taxes (90%-100%) Operating cash flow 1Average outstanding net debt plus preferred of $15.5 billion with 8.25% effective cost $3,200-$3,575 1,150 2,050-2,425 1,300 750-1,125 250-400 $500-$725 $1,150 250-350 $1,900-$2,225 $0.75-$1.10 $2.80-$3.30 $ Per Share 2006

2006 Core Earnings Buildup $ Millions Pipelines Production and processing International power Marketing and trading Midstream interest Corporate and other Total $1,400-$1,500 425-675 225-250 - 70-80 (70)-(80) $2,050-$2,425 $450 625 60 - - 15 $1,850-$1,950 1,050-1,300 285-310 - 70-80 (55)-(65) $3,200-$3,575 Segment EBIT DD&A EBITDA 2006

Free Cash Flow $ Millions Operating cash flow Working capital changes and other1 Capital expenditures Dividends on common stock Free cash flow2 $1,900-$2,225 - 1,600-1,700 100-125 $200-$400 2006 Target 1Assumes no significant source or use from working capital 2Does not include repayment of debt

What Is Not In Our Core Asset Base: Power Domestic contracted assets Domestic merchant assets 9 restructured merchant plants 3 merchant plants Turbine inventory Restructured contract assets European assets and other $750-$900 (50)-(75) 50-150 100-125 TBD1 50-100 $900-$1,200 First half 2004: 75%+ 2005: Remaining Mid-year 2004 2005 Throughout 2004 and 2005 Throughout 2004 and 2005 Throughout 2004 and 2005 1Net cash value after debt Assets Summary Value Range Likely Timing $ Millions

What Is Not In Our Core Asset Base: Petroleum and Production Petroleum: Aruba refinery Eagle Point refinery Other (nitrogen, MTBE, etc.) Production: Canadian assets Domestic assets and other $500-$6001 $600-$700 First half of 2004 Year end 2003 or 1Q 2004 4Q 2003 through mid-2004 First half of 2004 Throughout 2004 and 2005 1Value range net of Aruba lease of $370 MM and inclusive of working capital Assets Likely Timing $ Millions Summary Value Range

What Is Not In Our Core Asset Base: Field Services and Other GTM transaction with EPD Pipeline and other $1,000 $250-$350 $ 1,250-$1,350 4Q 2003, 2004 Throughout 2004 and 2005 Assets Summary Value Range Likely Timing $ Millions Of the $3.3 billion-$3.9 billion planned asset sales, $1.4 billion have been announced

Debt Reduction Plan Fourth Quarter 2003 $ 21,120 (1,643 ) 19,477 (200 ) (140 ) (400 ) - - 150 $ 18,887 Outstanding debt at 9/30/03 Less: Cash Net outstanding debt at 9/30/03 Recourse changes October/November 2003 maturities Repayment of term loan Bank revolver Non-recourse changes Linden Macae Available cash adjustment Estimated pro forma net outstanding debt at 11/30/03 Recourse $ Millions Non-recourse $ 2,460 - 2,460 - - - (571 ) 199 - $ 2,088

Debt Reduction Plan December 2003 Through 2005 $18,887 (1,200-900) (700-600) (600-500) (1,000) (350-250) (3,850-3,250) (300) (300-200) (600-500) (575) 455 300 $14,617-$15,317 Estimated net outstanding debt at 11/30/03 Asset sales (12/2003-12/2005) Power Production Petroleum Field Services Other Asset sales subtotal Working capital recovery: Trading Adequate assurance and other Working capital recovery subtotal ESU conversion Cash payments to Western Energy Settlement parties Cheyenne Plains project finance Target net outstanding debt at 12/31/05 Recourse $ Millions Non-recourse $ 2,088 (1,788 ) - - - - (1,788 ) - - - - - - $ 300

Sources of Volatility Natural gas Discount rates (contract exposure) Euro (financing) Mark-to-market +-$.10/Mcfe = +-$.03/share +-50 bps = +-$.05/share +-10% = +-$.04/share TBD Assumes 85% of 1 Bcfe/d target is natural gas Does not include impact of hedge position Assumes no sales of contract positions beyond MRF I and MRF IV Does not include financing exposure to interest rate movement Impact of movement on unhedged Euro exposure of &128; $425 MM Source of Volatility Annual Exposure Comments Quarterly impact in marketing and trading and domestic power

Sources of Volatility Significant items: Severance and restructuring cost Impairments Ceiling test charges Asset sales - - - - Based upon cost reduction activities Real estate moves may require charge Exposure in power, power contracts, telecom, LNG, and other areas Exposure in production Continue to create discontinued operations and gains/losses Source of Volatility Annual Exposure Comments

Key Milestones Pipeline EBIT growth Production Volumes (MMcfe/d) DD&A rate ($/MMcfe) Cash costs ($/MMcfe) Power EBIT growth Cash recovery through cash flow and financing Marketing EBIT contribution (2)%-2% 850-950 $1.85-$2.10 $0.95-$1.10 0%-5% $250 MM $(150)-$(75) MM 3%-5% 900-1,000 $1.75-$1.90 $0.80-$1.00 0%-5% $250 MM $(75)-$(25) MM Metric 2004 2005

Key Milestones Debt reduction Year-end total net debt Average interest cost (net) Tax rate Book Cash1 $18-$17 8.25% 35% 0%-10% $15 8.25% 35% 0%-10% Metric $ Billions 1Current net operating loss (NOL) in excess of $2.0 billion 2004 2005

Liquidity Update $ Billions Available cash1 Availability under $3 billion bank facility Net available liquidity Nov. 30, 2003 $ 1.1 1.0 $ 2.1 1Cash payout to Western Energy Settlement escrow account completed

Maturity Schedule1 $ Billions Capital market debt Gemstone Bank term loan and revolver3 Other Total 2004E $ 0.3 1.0 0.4 0.1 $ 1.8 2005E $ 0.4 2 - 0.9 0.3 $ 1.6 1Adjusted for significant retirements and issuances in 4Q 2003 2Excludes $75 MM puttable debt 3Reflects estimated funded debt at December 31, 2003 and does not reflect any outstanding letters of credit Note: A complete debt schedule and maturity schedule along with a legal organizational chart has been posted at http://www.elpaso.com/investor/debt.shtm El Paso expects significant liquidity through 2005 given $2.1 billion of liquidity at November 30, 2003 and $3.3 billion-$3.9 billion of planned asset sales

Financial Summary Strong liquidity expected throughout next 2 years; asset sales process well advanced 2006 core net income target of $500 MM- $725 MM, or $0.75-$1.10 per share 2006 core cash flow from operations target of $1.9 billion-$2.2 billion Annual growth and maintenance capital of $1.6 billion-$1.7 billion Target debt (net of cash) of $15 billion by end of 2005

Pipeline Group

El Paso Pipeline Group Broad footprint in North American market Poised for growth Key business drivers Capital and O&M cost management Continued recontracting success Management of rate and regulatory issues Stable earnings and cash flow with 2%-5% annual earnings growth

Broad Footprint in North American Market ANR Pipeline 10,600 miles; 6 Bcf/d Tennessee Gas Pipeline 14,200 miles; 6 Bcf/d El Paso Natural Gas 10,600 miles; 5 Bcf/d Colorado Interstate Gas 4,000 miles; 3 Bcf/d Elba Island LNG 4 Bcf Great Lakes Gas Transmission (50%) 2,100 miles; 3 Bcf/d Florida Gas Transmission (50%) 4,800 miles; 2 Bcf/d Mexico Ventures 106 miles; 1.6 Bcf/d Wyoming Interstate 600 miles; 2 Bcf/d Southern Natural Gas 8,200 miles; 3 Bcf/d Mojave Pipeline 400 miles; 0.4 Bcf/d

Great Expectations for Market Growth Tcf/yr. Bcf/d 2002 2010 2010 US Residential & Commercial 21.7 24 25.2 US Industrial 18.7 17.5 17.5 US Power Generation 15.8 19.9 21.3 US Pipeline Fuel; Lease & Plant 5.3 5.6 5.7 Canada 8.7 10.7 10.5 Mexico 4.1 7.2 8.7 27.1 Tcf/yr. 74.3 Bcf/d 31.0 Tcf/yr. 84.9 Bcf/d 32.4 Tcf/yr. 88.9 Bcf/d 2002 2010 El Paso NPC (BF) Mexico Canada U.S. Pipeline Fuel; Lease and Plant U.S. Power Generation U.S. Industrial U.S. Residential and Commercial

Poised for Regional Demand Growth 15.9 13.9 15.2 4.3 4.4 4.7 Mexico 5.0 5.9 6.4 Western Canada Eastern Canada NW and Alaska 2.8 2.9 3.2 Maritimes and Northeast U.S. 3.5 3.5 3.8 +2.6 +2.1 +1.2 +0.4 2.3 2.4 2.7 10.6 11.3 11.8 9.0 9.7 11.1 9.5 10.4 12.1 +1.2 5.9 6.5 7.1 EPG CIG TGP SNG FGT ANR GLGT +0.6 1.6 1.9 2.2 +4.6 4.1 7.2 8.7 EPG TGP MV Bcf/d Source: El Paso Pipeline Group Total North American Daily Demand 2002 74.3 2006 80.0 2010 88.9

Meeting the Supply Challenge LNG Arctic Mexico Canada Lower 48 2002 2010 2010 Lower 48 51 51.9 53 Canada 17.9 18.3 19.1 Mexico 3.5 4.9 6.3 Arctic 1.2 2.3 2.5 LNG 0.7 7.5 8 27.1 Tcf/yr. 74.3 Bcf/d 31.0 Tcf/yr. 84.9 Bcf/d 32.4 Tcf/yr. 88.9 Bcf/d 2002 2010 El Paso NPC (BF) Tcf/yr. Bcf/d

Western Canada Arctic 1.2 1.2 2.5 17.4 17.7 17.5 Rockies 14.1 15.2 15.1 Eastern Canada Mexico 3.5 5.8 6.3 Gulf of Mexico +1.0 +1.1 +0.2 +1.4 +0.9 +0.7 +2.8 +0.7 Poised for Regional Supply Growth SNG TGP ANR SNG FGT CIG Mexico Ventures Seafarer Blue Atlantic +2.8 +0.7 5.2 7.2 8.3 +3.1 0.5 0.6 1.6 Bcf/d Source: El Paso Pipeline Group Total North American Daily Supply 2002 74.3 2006 80.0 2010 88.9

TGP So. TX Expansion (Rio Bravo) $37 MM September 2003 312 MMcf/d Pursuing Growth Opportunities 2002-2010 (Bcf/d) 0.4 1.2 1.2 1.2 MacKenzie 0.3 -0.4 0.6 -0.5 -0.9 2.9 3.51 1Includes 2.8 LNG 0.5 0.4 0.3 0.6 0.4 0.7 0.7 .3 .4 0.2 1.4 0.2 N.A. LNG Imports 7.3 0.1 0.9 .3 0.7 Blue Atlantic Pipeline $2 billion 2008 1,000 MMcf/d Seafarer Pipeline $267 MM 2008 750 MMcf/d MV San Fernando Pipeline $230 MM 2003 1.0 Bcf/d EPNG Line 2000 Power Up $140 MM Spring 2004 327 MMcf/d ANR Westleg $45 MM 2004 218 MMcf/d CIG Medicine Bow Expansion $60 MM 2006-2008 590 MMcf/d CIG Cheyenne Plains $422 MM 2005-2006 730 MMcf/d 0.6 EPNG Line 1903 $82 MM Nov 2004 320 MMcf/d EPNG Copper Eagle Storage $234 MM 2007-2008 9.6 Bcf ANR Eastleg $21.3 MM 2005 142 MMcf/d SNG Elba Island Expansion $155 MM 1Q 2006 3.3 Bcf SNG North and South System $410 MM 2002-2003-2004 699 MMcf/d FGT Phase VI Expansion $105 MM 2003 120 MMcf/d TGP Freedom Trail Expansion $82 MM 2006 150 MMcf/d TGP Northeast ConneXion $217 MM 2007 100-200 MMcf/d

0.4 1.2 1.2 1.2 MacKenzie 0.3 -0.4 0.6 -0.5 -0.9 2.9 3.51 1Includes 2.8 LNG 0.5 0.4 0.3 0.6 0.4 0.7 0.7 .3 0.4 0.2 0.8 0.3 1.4 0.2 N.A. LNG Imports 7.3 0.1 0.9 .3 0.7 Blue Atlantic Pipeline $2 billion 2008 1,000 MMcf/d Seafarer Pipeline $267 MM 2008 750 MMcf/d SNG North and South System $410 MM 2002-2003-2004 699 MMcf/d FGT Phase VI Expansion $105 MM 2003 120 MMcf/d MV San Fernando Pipeline $230 MM 2003 1.0 Bcf/d EPNG Line 2000 Power Up $140 MM Spring 2004 327 MMcf/d ANR Westleg $45 MM 2004 218 MMcf/d CIG Medicine Bow Expansion $60 MM 2006-2008 590 MMcf/d CIG Cheyenne Plains $422 MM 2005-2006 730 MMcf/d EPNG Line 1903 $82 MM Nov 2004 320 MMcf/d EPNG Copper Eagle Storage $234 MM 2007-2008 9.6 Bcf ANR Eastleg $21.3 MM 2005 142 MMcf/d SNG Elba Island Expansion $155 MM 1Q 2006 3.3 Bcf TGP Freedom Trail Expansion $82 MM 2006 150 MMcf/d TGP Northeast ConneXion $217 MM 2007 100-200 MMcf/d 0.6 Pursuing Growth Opportunities 2002-2010 (Bcf/d) TGP So. TX Expansion (Rio Bravo) $37 MM September 2003 312 MMcf/d

Key Business Drivers: Capital and O&M Costs Effectively manage capital and expansion programs 5-year program: $850 MM per year average1 (range: $800 MM to $900 MM per year) Maintenance/integrity/safety/environmental capital: $450 MM per year Growth and expansion capital: $400 MM per year Maintain strict O&M cost control discipline Achieve the Pipeline Group's share of additional cost savings target 1Excludes Cheyenne Plains project financing of approximately $300 MM

2004 2005 2006 2007 2008 2009 2010 Beyond TGP 1247 1144 519 533 513 559 352 2302 ANR 1192 778 1482 142 801 132 1300 1348 EPNG 643 563 2488 1469 0 0 11 590 CIG 206 165 223 996 163 462 229 1689 SNG 0 1180 184 512 374 14 282 808 Key Business Drivers: Recontracting Contract Portfolio Dekatherms TGP ANR EPNG CIG SNG 12% 3,288 14% 3,830 18% 4,896 13% 3,652 1,851 1,167 2,174 6,737 Average remaining contract term: 41/2 years

Key Business Drivers: Rate and Regulatory Manage rate and regulatory issues EPNG risk sharing reservation surcharge Rate cases FGT April 2004 SNG March 2005 EPNG January 2006 CIG October 2006 Mojave March 2007

Asset Divestitures TGP: MGT1 ANR: Empire1 ANR: Iroquois1 ANR: Gulfstream1 ANR: Destin1 SNG: Sea Robin1 ANR: Alliance ANR: Typhoon CIG: Panhandle Production CIG: Trailblazer TGP: Coastal Australia ANR: Steuben CIG: Table Rock CIG: Keys Helium TGP: PNGTS Total 1Required by FTC consent decree $ 95.6 77.6 42.6 47.8 161.0 75.0 $ 499.6 $ 165.0 51.0 133.0 11.3 $ 360.3 $ 24.0 19.2 7.0 7.4 9.0 56.4 $ 123.0 $ 95.6 77.6 42.6 47.8 161.0 75.0 189.0 51.0 133.0 11.3 19.2 7.0 7.4 9.0 56.4 $ 982.9 2001 2002 2003 Total $ Millions

Stable Earnings and Cash Flow $ Millions EBIT EBITDA Annual EBIT growth Capex $ 1,335 $ 1,725 2%-5 % $ 850 EBIT DD&A EBITDA Capex $ 1,400-$1,500 $450 $1,850-$1,950 $800-$9001 2003 Estimates 2006 Do not expect growth in 2004, but growth at high end of range for following years of plan Sensitivities Weather/gas prices Macro gas balance/competitive dynamics 1Excludes Cheyenne Plains project financing

0.4 1.2 1.2 1.2 MacKenzie 0.3 -0.4 0.6 -0.5 -0.9 2.9 3.51 1Includes 2.8 LNG 0.5 0.4 0.3 0.6 0.4 0.7 0.7 .3 0.4 0.2 0.8 0.3 1.4 0.2 N.A. LNG Imports 7.3 0.1 0.9 .3 0.7 Blue Atlantic Pipeline $2 billion 2008 1,000 MMcf/d Seafarer Pipeline $267 MM 2008 750 MMcf/d SNG North and South System $410 MM 2002-2003-2004 699 MMcf/d FGT Phase VI Expansion $105 MM 2003 120 MMcf/d MV San Fernando Pipeline $230 MM 2003 1.0 Bcf/d EPNG Line 2000 Power Up $140 MM Spring 2004 327 MMcf/d ANR Westleg $45 MM 2004 218 MMcf/d CIG Medicine Bow Expansion $60 MM 2006-2008 590 MMcf/d CIG Cheyenne Plains $422 MM 2005-2006 730 MMcf/d EPNG Line 1903 $82 MM Nov 2004 320 MMcf/d EPNG Copper Eagle Storage $234 MM 2007-2008 9.6 Bcf ANR Eastleg $21.3 MM 2005 142 MMcf/d SNG Elba Island Expansion $155 MM 1Q 2006 3.3 Bcf TGP Freedom Trail Expansion $82 MM 2006 150 MMcf/d TGP Northeast ConneXion $217 MM 2007 100-200 MMcf/d 0.6 Pursuing Growth Opportunities 2002-2010 (Bcf/d) TGP So. TX Expansion (Rio Bravo) $37 MM September 2003 312 MMcf/d

Employee Safety Performance November Year-to-date 2003 2002 2003 Pipeline Group goal 2002 AGA rate 65 79 13 20 1.81 2.13 1.92 1.94 0.36 0.54 0.55 0.60 Total Recordable Incidents Days Away Incidents TRIR DAIR

Summary Large, stable, and diversified Pipeline Group Broad footprint, poised for growth Proven track record managing the key business drivers Stable earnings and cash flow with 2%-5% annual earnings growth

Exploration and Production

Near-term Goals Conclude rationalization Fit competencies to basins Return to cost leadership LOE G&A Improve capital efficiency Improve predictability Pay for performance

EPPC Global Operations: Pre Divestiture Australia Indonesia Turkey Egypt Hungary Brazil Peru Bolivia Argentina Ivory Coast Algeria Venezuela Mexico U.S. Canada

EPPC Global Operations: Post Divestiture Nova Scotia Brazil U.S.

EPPC: U.S. Pre Divestiture Wind River Washington CBM Arkoma CBM North Louisiana Catapult Gulf of Mexico Black Warrior CBM San Juan Raton CBM Anadarko East Texas Onshore Texas Uinta Piceance Green River

EPPC: U.S. Post Divestiture Wind River Arkoma CBM North Louisiana Catapult Gulf of Mexico Black Warrior CBM Raton CBM Onshore Texas Green River

Portfolio Rationalization: Actions Taken Year 2002 sales of $1.3 billion Year-to-date 2003 of $740 MM Altamont/Bluebell $50 MM Current planned offerings Some mature Gulf of Mexico and South Texas properties Canada Brazil (strategic partner) Indonesia

Portfolio Rationalization: El Paso Production Basins Growth basins Rockies/CBM responsible for 65% of production growth North Louisiana/E. Texas: Frac technology driving production Deep Shelf GOM: Technology driven play Stable basins Texas Gulf Coast: Access issues restricting exploration Permian Declining basins Mid Continent: El Paso sold in 2003 Shallow Shelf GOM: El Paso transitioning out Eastern Gulf Coast Future investment aligned with NPC growth basins

Portfolio Rationalization: 2003-2004 Production Capital 2003 $1,400 MM 2004 $850 MM Texas Onshore Gulf of Mexico Coalbed Methane Central Canada, Brazil, and Other Exploration $420 MM 30% $295 MM 21% $150 MM 11% $90 MM 7% $225 MM 16% $220 MM 15% $165 MM 19% $210 MM 25% $215 MM 25% $60 MM 7% $145 MM 17% $55 MM 7%

Key Drivers for Future Investment

Texas Onshore Legacy asset with operational momentum Stable basin with good resource potential and excellent service network Significant infrastructure that can be utilized for expansion Large lease position (approx. 285,000 net acres) with expansion opportunities Excellent 3D seismic coverage (21,780 sq. miles)

GOM Deep Shelf Immature basin with excellent resource potential Existing sales/processing infrastructure Excellent land position 3D seismic coverage available from mature Shallow Shelf play 60% exploratory success rate Manned facilities Unmanned facilities Leases (as of October 31, 2003)

Coalbed Methane Excellent set of assets Significant future potential: Over 1 MM gross acres Low cost reserves Raton Arkoma Black Warrior El Paso Coalbed Methane Operations

Production expected to double between 2003 and 2006 Coalbed Methane Production and Reserve Growth 1,439 Production Reserves 1Raton/Devon acquisition Bcf/yr. EOY Reserves-Bcf 1998 1999 2000 2001 2002 2003E 1997 1997 1998 1999 2000 2001 2002 5031

Central Proven basin of successful development Significant future potential Acquisition opportunities Good cash flow properties

Full Cycle Economic Targets Henry Hub ($/MMBtu) Difference to Henry Hub Average net back price Lease operating and work over expense Production and ad valorem taxes General and administrative Full-cycle F&D cost Profit per unit 1El Paso 3-year expected F&D cost due to conversion of PUD reserves to PDP $4.25 0.04 4.29 0.26 0.01 0.36 2.10 2.73 $1.56 $4.25 (0.64 ) 3.61 0.40 0.26 0.36 1.10 1 2.12 $1.49 $4.25 (0.14 ) 4.11 0.34 0.10 0.36 1.40 2.20 $1.91 GOM Deep Shelf Coalbed Methane Central $4.25 0.02 4.27 0.21 0.19 0.36 2.00 2.76 $1.51 Texas Onshore $/Mcfe, Except Henry Hub

Annual New Development Targets Texas Onshore Gulf of Mexico Coalbed Methane Central Total F&D Range ($/Mcfe) Reserve Range (Bcfe) Basin Reserve/ Production Ratio Target Production Range (Bcfe) $200 300 225 80 $805 Capital ($ MM) Area $1.80-2.15 1.90-2.25 1.00-1.20 1 1.25-1.50 $1.44-1.73 90-110 130-160 190-225 55-65 465-560 6 4 25 10 8 15-18 33-40 8-9 6-7 62-74 Daily equivalent production range 170-200 MMcfe/d 1El Paso 3-year expected F&D cost due to conversion of PUD reserves to PDP

2004 Production Target Ranges Beginning 2004 production rate1 Annual PDP decline 25%-40% Production before new development New development from $850 MM capital Production target ranges 860 (180 ) 680 170 850 MMcfe/d 860 (110 ) 750 200 950 High Low 1Based on November 2003 production of 990 MMcfe/d less production from planned property sales

Expected Natural Gas Equivalent Production: United States Operations MMcfe/d Proved Developed Producing Exploration and Acquisition Opportunity New Development Drilling Investment Program

Investor drilling program Investors to contribute 70% of estimated $500 MM drilling costs associated with El Paso drilling program ($350 MM) Exploration ventures Onshore Texas: 9 prospects South Louisiana (Catapult): 3 prospects GOM deep shelf: 2 prospects Outside Funding Outside funding has resulted in >$380 MM of increased capital opportunities Investors' share of production El Paso share of production Net gas (MMcf/d) Months of production Well Production Profile

El Paso Production Company Safety Performance (YTD) BLS: Bureau of Labor Statistics Total Recordable Incident Rate (TRIR): Number of injuries as defined by OSHA for every 200,000/manhours Days Away Incident Rate (DAIR): Days away as defined by OSHA for every 200,000/manhours 2003 2002 BLS Rate 5 11 2 3 0.54 0.89 3.30 0.21 0.24 1.70 Total Recordable Incidents Days Away Incidents TRIR DAIR Employee Performance 2003 2002 BLS Rate 89 124 41 49 2.12 2.15 3.30 0.98 0.85 1.70 Total Recordable Incidents Days Away Incidents TRIR DAIR Contractor Performance

El Paso Production Company Exploration Strategy

Exploration Strategy Assumptions Substantial deep gas resources on Gulf Coast (MMS just raised potential in Deep Shelf to 55 Tcf) Industry focus on domestic M&A and deepwater will continue to make opportunities available to El Paso North American gas deliverability will continue to be a challenge Federal government will continue to limit access to key areas

Gulf Coast Deep Gas: The Opportunity Relatively unexplored Large reserves High flow rates Strong onshore South Louisiana analog Huge existing infrastructure Deep gas royalty relief-OCS

Gulf Coast Deep Gas: Competitive Advantage Regionally focused 3D acquisition Leading seismic data base Internal seismic processing Large acreage position Multi-year prospect inventory Strong portfolio management

Gulf of Mexico Shelf: 0-600' Water Depth 0-600' Water Depth 0-600' Water Depth Currently there are 2,810 wells > 15,000' TVD This compares to 2,528 < 15,000' TVD wells completed by 1958

Objectives Material reserve exposure Capable of high flow rates Generally deep (>15,000') Looking for company sustaining discoveries

Vicksburg Trend EPPC 100% EPPC Partial EPPC Option 3D Seismic

Wilcox Trend Bob West Loma Veija N. Gov't Wells Muy Grande George West Cuellar Hope / Brushy Creek McCaskill Speaks Bonus Dry Hollow EPPC 100% EPPC Partial EPPC Option

LAKE CHARLES LAYFAYETTE Deep Shelf Trends LOUISIANA

LAKE CHARLES LAYFAYETTE Catapult/Bayou Sale JB Mountain CATAPULT BAYOU SALE Mound Point

LAKE CHARLES LAYFAYETTE Significant Onshore South Louisiana Discoveries Since 1980 Kent Bayou / Etouffee - 2000 130 Bcfe Total cumulative production in excess of 2.7 Tcfe Freshwater / N. Freshwater Bayou - 87 / 94 380 Bcfe Broussard - 84 240 Bcfe N.W. Myette Point - 96 185 Bcfe Riceville - 98 195 Bcfe CATAPULT BAYOU SALE S. Lake Arthur - 82 860 Bcfe W. Chalkley - 89 475 Bcfe Wright - 01 40 Bcfe Leleux Deep - 82 285 Bcfe Scott Deep - 91 215 Bcfe

LAKE CHARLES LAYFAYETTE Catapult Inventory South Little Lake Misere Black Fish Lake Florence Canal Long Point Cane Ridge Florence Canal East

Process: Prospect Generation Driven by regional 3D seismic data Trend focused with regional understanding of depositional environments Aggressive lease acquisition Able to act quickly to identify and capture opportunities

Process: Portfolio Management Evergreen prospect inventory Accurate estimates enable pro-active management Utilize appropriate indices for prospect selection Monitor and manage key portfolio dimensions Manage risk and exposure through strategic partnering

Process: Portfolio Management Critical mass (minimum 20-25 trials) Suitability: Portfolio should deliver predictable performance on key metrics Reserves/Production/F&D cost Post drilling evaluation Failure analysis Investment results

Quinn McCaskill Kings Dome Major Discovery Index Map Jim Bob Mtn. ST 212 North Quinn N. Monte Christo 52 Bcfe 39 MMcfe/d Santa Fe Ranch 154 Bcfe 54 MMcfe/d Pueblo/Kingsville 41 Bcfe 48 MMcfe/d Prospect 8/8ths Current Cum. Current Rate ST204 243 Bcfe 98 MMcfe/d Year of Discovery 2003 2002 2001 WC46/47 36 Bcfe 88 MMcfe/d Mound Point 2 Bcfe 37 MMcfe/d JB Mountain 5 Bcfe 36 MMcfe/d

Exploration Current Prospect/Lead Inventory Vicksburg/Frio Wilcox Deep Shelf Catapult Miscellaneous 19 18 23 6 13 79 385 200 295 40 135 1,055 No. of Prospects Net Risked Mean (Bcfe)

2004 Domestic Exploratory Program Wilcox Trend 4 wells Vicksburg Trend 4 wells Catapult 5 wells Deep Miocene Trend 4 wells Frio Trend 2 wells Rockies 1 well Total Domestic Exploration 21 gross wells North Louisiana 1 well

Cumulative Results 2000-2003 0 10 20 30 40 50 60 0 25 50 75 100 Prospects Drilled Number of Discoveries DISCOVERIES 0 250 500 750 0 25 50 75 100 Prospects Drilled Cumulative Net A/R Proved (Bcfe) 0 100 200 300 400 500 600 0 25 50 75 100 Prospects Drilled Cumulative Net DHC ($MM) Predicted = 36 of 89 (Ps=40%) Actual = 48 of 89 (Ps = 54%) EST. PROVED RESERVES Actual = 692 Bcfe Predicted = 553 Bcfe Predicted = $404 MM Actual = $491 MM DRY HOLE COST + RCC El Paso Exploration Performance 2000-2003 YTD Historical Perspective Total exploration expenditures: $769 MM Total proved reserves found: 692 Bcfe 3-year proved finding cost: $1.11 per Mcfe Total estimated 3P reserves found: 960 Bcfe 3-year 3P finding cost: $0.80 per Mcfe

Conclusions Trend selection critical in achieving desired results Significant resource base available in deep section of Gulf Coast Target trends demand high level of technical integration Current technology adequate to meet challenge El Paso Production has the skills, resources, and opportunity inventory needed to continue to profitably find and deliver natural gas

Merchant Energy Group Marketing and Trading Global Power

Merchant Energy Highlights Marketing and Trading highlights Continued progress in the liquidation of trade book 70% of remaining positions terminate by the end of 2004 Substantial return of cash collateral Reduction in risk metrics

Merchant Energy Highlights Global Power highlights Strong earnings power Strong cash flows Long-term contracted earnings and cash flows Low capital requirements Manage for value and return of cash

Marketing and Trading

Marketing and Trading Business Plan Exit trading business Maximize return of cash Liquidate the majority of positions by the end of 2004 Liquidate limited number of longer term contracts when market conditions warrant Continue to manage the marketing of El Paso Production natural gas

Marketing and Trading Projected EBIT and Cash Major milestones prior to 2006: Reduce G&A to $15 MM Release or terminate accrual contracts, including excess transportation and storage contracts not utilized for EPPC production $ Millions EBIT Cash flow $(375)-$(400) $360-$400 $ - $ - 2003 2006

Marketing and Trading G&A $ Millions 1Reflected in plan estimates as interest on debt Employee and overhead costs Depreciation Settlement accretion Total $ 91 25 47 $ 163 $ 12 3 - 1 $ 15 2003 Forecast 2006 Forecast

Remaining Forward Transactions Nov. 2003 Forward 2004 2005 2006 2007 and Beyond Exchange transactions 751 1230 274 61 46 Financial swaps 2780 1708 424 194 309 Options 148 71 9 2 0 Physical forwards 3718 2263 1097 690 1758 Other transactions 277 290 176 154 882 7,674 40%1 5,562 29%1 1,980 10%1 2,995 15%1 Exchange transactions Financial swaps Options Physical forwards Other transactions Number of Transactions As of October 31, 2003 1Percent of total rolling-off Note: Transaction is defined as one contract within a calendar year; If a contract extends 5 years, then it is counted as 5 transactions 1,101 6%1

Trading: Liquidation Status 52% reduction in forward positions 65% reduction in physical gas sales 36% reduction in physical power sales 68% reduction in transportation capacity 86% reduction in storage capacity 64% reduction in headcount December 31, 2002-October 31, 2003

Marketing: EPPC Production Maximize wellhead net-back and ensure all gas flows to markets EPPC natural gas is located in premium supply basins that command strong pricing EPPC natural gas is available for several of the Trading Division's longer term contracts Serves as the primary source of collateral minimization

Global Power

Global Power Business Plan Exit domestic power business Manage and optimize the cash flows of the international power business Review sale opportunities within 3-5 years Integrate the Brazilian power and pipeline business with the E&P operations

Current Profile of Global Power Assets As of October 31, 2003 U.S. South America Central America & Europe Asia Total Number of plants Number of pipelines 4,521 1,786 598 1,985 8,890 69 3 $ 2,045 1,328 449 678 $ 4,500 16 countries 514 net km Net MW Net Book Value $ Millions

Domestic Power Assets As of October 31, 2003 Merchant: 1,955 net MW 2,363 gross MW Contract: 2,566 net MW 5,040 gross MW

Domestic Power Assets As of October 31, 2003 Contracted power plants: 27 plants; 2,566 net MW Merchant power plants: 12 plants; 1,955 net MW Restructured contract assets: $ Millions Cedar Brakes I Cedar Brakes II MRF II Mohawk River Funding IV Utility Contract Funding Total $ 297 399 50 77 829 $ 1,652 $ 126 234 41 17 99 $ 517 Non-recourse Debt Net Book Value $ 25 40 11 2 69 $ 147 As of October 31, 2003 Forecasted Annual 2003 EBIT

South America As of October 31, 2003 Bolivia-to-Brazil Pipeline (3,150 km) Porto Velho (409 MW) Urucu Pipeline (538 km) Note: Urucu Pipeline under construction Aguaytia1 (155 MW) Argentina-to-Chile Pipeline (540 km) Rio Negro (158 MW) Manaus (238 MW) Macae (895 MW) Araucaria (484 MW) Gross MW Power1: 1,786 net MW Pipeline: 514 net km 1Aguaytia is included with Central America results for management reporting

Central America As of October 31, 2003 Nejapa 144 MW (El Salvador) Pacora 50 MW (Panama) Itabo 513 MW (Dominican Republic) Tipitapa 51 MW (Nicaragua) GEOSA 115 MW (Nicaragua) Fortuna 300 MW (Panama) CEPP 67 MW (Dominican Republic) Gross MW Total: 4681 net MW 1Aguaytia is included with Central America results for management reporting

Europe As of October 31, 2003 EMA Power 69 MW Enfield 378 MW Total: 130 net MW Gross MW

Asia As of October 31, 2003 Wuxi 39 MW PPN 325 MW Khulna 113 MW Haripur 116 MW Meizhou Wan 734 MW KIECO 1,720 MW Sengkang 135 MW Suzhou 109 MW Fauji Kabirwala 157 MW Quetta 136 MW Saba 128 MW Nanjing 75 MW East Asia and CEBU 324 MW Total: 1,985 net MW Gross MW

Projected Profile of Global Power Assets South America Central America Asia Total Number of plants Number of pipelines 1,710 468 1,985 4,163 28 3 $ 1,084 328 682 $ 2,094 13 countries 514 net km Estimated Net MW Estimated Net Book Value As of December 31, 2006 ($ Millions) Note: Profile of assets after domestic power plant sales, sale of European assets, and recontracting of 2 Brazilian power plants

International Earnings Under Contract Global Power: % of Total EBIT From Long-term PPAs International Brazil Central America and Europe Asia % of total international power 100 % 54 % 100 % 95 % 2003 100 % 55 % 100 % 95 % 2004 97 % 43 % 100 % 92 % 2005 95 % 34 % 100 % 90 % 2006 Note: Excludes group overheads and corporate allocation Average length of International PPA: 11 years Brazil: 9 years Central America and Europe: 6 years Asia: 15 years

Projected EBIT, EBITDA and Capex 1Excluding gain/loss on asset sales, impairments, and other significant items Global Power ($ Millions) Major milestones prior to 2006: Sale of all domestic power assets (including power restructuring contract assets) and European assets Recontracting/restructuring of 3 Brazilian power plants Project financing in Brazil and Asia Restructuring of several PPAs in Asia EBIT1 EBITDA Capex $480-$500 $550-$590 $40 $ 225-250 $275-300 $10-20 2003 2006

Key Takeaways: Marketing, Trading, and Global Power Continue liquidation of trade book for return of cash Retention of talented organization to market EPPC production Sale of domestic power assets Strong contracted earnings and cash from international power assets Manage international power assets for value and return of cash

Closing

What Did We Tell You Purpose and values How we're governed What we're going to be What we have to do What the target results will be It won't happen over night Our goals are attainable

Long-Range Plan December 2003