EXHIBIT 99.A

2005 Analyst Meeting March 17, 2005

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, changes in unaudited and/or unreviewed financial information; our ability to file our annual report on Form 10-K by March 31, 2005: the extent and timing of any restatement of financial statements; our ability to implement and achieve our objectives in the long-range plan, including achieving our debt-reduction targets; changes in reserve estimates based upon internal and third party reserve analyses; our ability to meet production volume targets in our Production segment; uncertainties and potential consequences associated with the outcome of governmental investigations, including, without limitation, those related to the reserve revisions and natural gas hedge transactions; outcome of litigation, including shareholder derivative and class actions related to reserve revisions and restatements; our ability to comply with the covenants in our various financing documents; our ability to obtain necessary governmental approvals for proposed pipeline projects and our ability to successfully construct and operate such projects; the risks associated with recontracting of transportation commitments by our pipelines; regulatory uncertainties associated with pipeline rate cases; 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 the company 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; 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. Non-GAAP Financial Measures This presentation includes certain Non-GAAP financial measures as defined in the SEC's Regulation G. More information on these Non-GAAP financial measures, including the required reconciliations under Regulation G, is set forth in the appendix hereto.

Schedule 8:30 a.m. Introduction Doug Foshee President and Chief Executive Officer 8:50 a.m. Financial Review Dwight Scott Executive Vice President and Chief Financial Officer 9:20 a.m. Non-Regulated Overview Lisa Stewart President, Production and Non-Regulated Operations 9:50 a.m. Regulated Overview John Somerhalder President, Pipeline Group 10:15 a.m. Summary 10:20 a.m. Q&A 10:45 a.m. Break Estimated Time (CST)

Schedule 11:00 a.m. Regional Pipeline Presentations Steve Beasley, President, Eastern Pipelines Jim Cleary, President, Western Pipelines Jim Yardley, President, Southern Natural Gas 11:45 a.m. Q&A Noon Lunch (no presentation) 1:00 p.m. Review of Production Regions Lisa Stewart President, Production and Non-Regulated Operations 2:15 p.m. Q&A 2:45 p.m. Review of Other Non-Regulated Mark Leland Executive Vice President and Chief Financial Officer, Non-Regulated 3:15 p.m. Q&A Estimated Time (CST)

Our Purpose El Paso Corporation provides natural gas and related energy products in a safe, efficient, and dependable manner

Values Stewardship Integrity Safety Accountability Excellence

Governance Update Continued Board evolution 8 of 12 new since January 2003 7 of 8 have significant upstream experience 2 of 8 qualify as financial experts Guidelines exemplify good corporate governance No staggered board No pill 11 of 12 board members are independent Separate Chairman and CEO positions

December 2003 vs. March 2005 Liquidity Asset sales Debt reduction target Renew bank facilities Cost reduction Fix E&P Free cash flow Free cash flow Value creation in E&P Debt reduction target Cost control Prior Issues Current Issues

Targets for 2006 Strong North American natural gas company $425 MM-$750 MM net income, or EPS of $0.58-$1.03 EBITDA: $2.9 billion-$3.5 billion Annual capex: $1.6 billion-$1.7 billion Net debt: $15.0 billion by 2005

Pipeline Outlook Fundamentals remain excellent Growth projects driven by new natural gas supplies Recontracting progress has been good Portfolio effect of franchise is evident Near-term cost increases overshadowing underlying growth

Production Outlook Substantial progress in last 12 months New management Production stabilizing Capital discipline More focus onshore Must demonstrate value creation in 2005

Financial Review The financial information provided herein should be considered preliminary and unaudited; it remains subject to further review and adjustment by El Paso and its independent auditor and subject to change.

Financial Outlook Methodology 2006 targets reflect updated objectives, new pricing environment Providing key milestones for 2005; El Paso's target for 2006 Continue to provide clear measure of progress vs. milestones

Long-Range Plan Financial Progress Debt Reduction Asset sales Cost reduction Liquidity Recover working capital $17.1 billion debt, net of cash, at 12/31/04 On track for $15 billion net debt at 12/31/05 $4.2 billion announced or closed vs. $3.3 billion-$3.9 billion plan Additional $1.2 billion-$1.6 billion targeted $50 MM of $150 MM in place Insurance, legal fees, audit, and Sarbanes compliance costs impeding progress near term Has remained strong New credit facilities in place Effectively addressing 2006 maturities Essentially accomplished Comments

2003 and 2004 Financial Results EBIT Interest and debt expense Preferred and minority interest (Loss) before income taxes Income taxes (Loss) from continuing operations Discontinued operations, net of tax Cumulative effect of accounting changes, net of income taxes Net loss $ 766 1,607 25 (866 ) 12 (878 ) (146 ) - $ (1,024 ) $ 769 1,791 52 (1,074 ) (551 ) (523 ) (1,396 ) (9 ) $ (1,928 ) Twelve Months Ended December 31, 2004 2003 $ Millions Note: See appendix for discussion on non-GAAP terms

Business Unit Contribution EBITDA DD&A EBIT Significant items Capital expenditures* $ 1,727 $ 410 $ 1,317 $ (5 ) $ 1,050 2004 $ 1,620 $ 386 $ 1,234 $ 118 $ 818 2003 $ 1,282 $ 548 $ 734 $ 22 $ 700 2004 $ 1,667 $ 576 $ 1,091 $ 16 $ 1,440 2003 $ (590 ) $ 54 $ (644 ) $ 1,053 $ 30 2004 $ 63 $ 91 $ (28 ) $ 528 $ 29 2003 $ (534 ) $ 13 $ (547 ) $ 2 $ - 2004 $ (784 ) $ 25 $ (809 ) $ (5 ) $ - 2003 $ (31 ) $ 63 $ (94 ) $ 96 $ 36 2004 $ (621 ) $ 98 $ (719 ) $ 611 $ 74 2003 Pipelines Production Power Marketing & Trading All Other $ Millions *Excludes capital expenditures for discontinued operations and acquisitions

Summary of 2004 Significant Items $ (38 ) (80 ) (1,582 ) 532 $ (1,168) Employee costs Facility closures Asset impairment & other Gain/(loss) on asset disposal Total significant items Total Pipeline Production Power Marketing & Trading Field Services $ (5 ) - - 10 $ 5 $ (14 ) - (8 ) - $ (22 ) $ (5 ) - (1,066 ) 18 $ (1,053) Twelve Months Ended December 31, 2004 $ (2) - - - $ (2) $ (1 ) - (504 ) 497 $ (8 ) Corporate and Other $( 11) (80) (4 ) 7 $ (88) $ Millions

Operating Cash Flow $ (878 ) 2,432 1,554 223 (461 ) 2 1,316 1,903 (2,531 ) $ 688 Net loss1 Non-cash adjustments to net loss Subtotal Discontinued operations Working capital changes and other Cash flow from operating activities Cash flow from investing activities3 Cash flow from financing activities3 Change in cash 2004 2003 $ (532 ) 1,761 1,229 25 1,075 2,329 (1,189 ) (1,302 ) $ (162 ) Twelve Months Ended December 31, $ Millions 1Excludes discontinued operations 2Includes $626 MM for Western Energy settlement payments 3Includes discontinued operations

2004 Summary Free Cash Flow $ 434 25 170 $ 629 (412 ) (46 ) (23 ) $ 148 $ 148 Operating cash generation Working capital changes and other* Discontinued operations Net cash provided by operating activities Capital expenditures Continuing operations Discontinued operations Dividends Quarterly free cash flow Cumulative free cash flow $ 337 (57 ) (9 ) $ 271 (391 ) (4 ) (26 ) $ (150 ) $ (2 ) $ 221 274 30 $ 525 (469 ) - (26 ) $ 30 $ 28 $ 562 (77 ) 32 $ 517 (544 ) - (26 ) $ (53 ) $ (25 ) March 31, 2004 June 30, 2004 September 30, 2004 December 31, 2004 *Excludes $626 MM for Western Energy settlement payments Three Months Ended $ Millions

Maturity Schedule at March 2, 2005 Capital market debt-Non-pipeline1 Pipeline capital market debt2 B-Loan Bank debt Other3 Total maturities El Paso Zero Coupon Convert Total including Zero Coupon Convert $ 216 180 20 10 79 $ 505 - $ 505 $ 344 - 20 11 122 $ 497 668 $ 1,165 2005E 2006E 1Assumes exchange rate on euro-denominated debt in effect on December 31, 2004 2Excludes Pipeline puttable debt of $75 MM in 2005 3Excludes in 2005 $219 MM of Macae maturities and $39 MM of Mohawk River Funding II debt which will be reclassified as current on the 12/31/04 balance sheet 4Includes $180 MM of proceeds from CIG financing set aside to pay Pipeline capital market debt of $180 MM in 2005 The company expects to have available liquidity of approximately $1.6 billion at March 31, 20054 $ Millions

2005 Items Potentially Impacting Operating Cash Flow 2005 discretionary items: CBI & CBII Western Energy prepayment Lease prepayment Trading early settlements $ (240 ) (450 ) (100 ) (300 ) 2005 Impact $ Millions Total potential impact to operating cash flow of approximately $1.1 billion in 2005

2005 Completed Asset Sales* Cedar Brakes I & II Enterprise Investment S. Louisiana processing plants Other Total $ 94 425 75 56 $ 650 Asset Associated Non-recourse Debt Proceeds $ 575 - - - $ 575 *January 1-March 15, 2005 $ Millions

Asset Sales: Remaining 2005 and 2006 Domestic Power International Power Field Services Other Remaining merchant plants (4) Midland Cogeneration Mohawk River Funding II Turbine inventory Asian plants Central American plants European plants South Louisiana Miscellaneous other Lakeside telecom facility Miscellaneous other Montreal Paraxylene Plant Segment Potential Assets $1.2 billion to $1.6 billion expected proceeds incremental to $650 million year to date

Debt Reduction Targets Outstanding debt at 12/31/04 Less: Cash Escrow on project finance Value of Euro hedges Net outstanding debt at 12/31/04 Asset sales (2005/2006) ESU conversion 2005 discretionary items Target net outstanding debt $ 18,255 (2,117 ) - (238 ) $ 15,900 (2,200-1,800) (272 ) 250-1,100 $13,678-$14,928 Recourse $ 941 - (125 ) - $ 816 (612 ) - - $ 204 Non-recourse Target of $15 billion is achievable, even given desire to address other liabilities in 2005 and to continue growth investment in business $ Millions

Key Milestones Pipeline EBIT Production Volumes (MMcfe/d) DD&A rate ($/Mcfe) Cash costs ($/Mcfe) Brazil Power EBIT Marketing EBIT* $1,300 MM-$1,350 MM 800+ $1.85-$2.10 $1.25-$1.40 $50 MM-$75 MM $(100) MM-$(75) MM $1,350 MM-$1,450 MM 825+ $1.85-$2.10 $1.10-$1.30 $50 MM-$75 MM $(75) MM-$0 MM 2005 2006 *Excluding impact of hedging activities

2006 Core Earnings Buildup (Excluding Hedges) Pipelines Production (825+ MMcfe/d at $5.50-$6.50/Mcf) Brazil power Marketing Corporate and other Total $1,350-$1,450 550-875 50-75 (75)-0 (25) $1,850-$2,375 $ 450 600 25 - 10 $ 1,085 EBIT DD&A EBITDA 2006 $1,800-$1,900 1,150-1,475 75-100 (75)-0 (15) $2,935-$3,460 Note: Hedge impact in 2006 of $(73) MM-$14 MM not included in this analysis $ Millions

2006 Core Earnings and Cash Flow EBITDA DD&A EBIT Interest and preferred at 8% Taxes at 35% Net Income Non-cash adjustments DD&A Non-cash taxes (90%) Working capital Operating cash flow Cash expenditures Dividends Free cash flow $2,935-$3,460 1,085 $1,850-$2,375 (1,200) (225)-(425) $425-$750 1,085 200-375 - $1,710-$2,210 1,600-1,700 110 $0-$400 $0.58-$1.03 $2.35-$3.03 $ Millions Per Share Note: Cash hedge impact in 2006 of $(71) MM-$(220) MM not included in this analysis

Areas of Focus to Improve Cash Flow Recurring incremental cost savings Eliminate recurring loss in marketing Achieve high end of production target Achieve low end of capital expenditure target Total $ 100 75 50 100 $ 325 2006 Potential Impact $ Millions

Financial Summary Strong liquidity expected throughout next 2 years; asset sales process well advanced 2006 core net income target of $425 MM-$750 MM, or $0.58-$1.03 per share 2006 core cash flow from operations target of $1.7 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

Non-Regulated Overview

2004 Overview E&P performance driven by higher realized prices, lower DD&A and production at low end of targets International power portfolio generated solid earnings Marketing and Trading negatively impacted by production hedges and higher gas prices Midstream benefited from solid operating performance and high commodity prices

Total Capex Production International Power Marketing & Trading Midstream Other Production 829 779 International Power 27 Marketin & Trading 0 Midstream 17 Other 6 2004 Non-Regulated Results Total EBIT Production International Power Marketing & Trading Midstream Other Production 777 756 International Power 323 Marketin & Trading -545 Midstream 128 Other 115 Adjusted EBIT1 Capex and Acquisition $ Millions 7792 1Adjusted for significant items (see page 16) 2Includes acquisitions

E&P Turnaround Regional structure implemented Drilling results measured and improving Onshore continues as foundation Offshore stabilizing with balanced program Texas Gulf Coast results less than expected International refocused

2004 Production 1Q04 2Q04 3Q04 4Q04 Texas Gulf Coast 308 306.7 262.4 253.4 Onshore 224 223 238 239 Offshore 368.6 274.4 237.6 225.3 International 0 0 37.7 57.7 2004 Average daily production 814 MMcfe/d* 901 804 776 775 MMcfe/d Texas Gulf Coast Onshore Offshore International *Excludes discontinued operations

Operations on Target Production (MMcfe/d)1 Capital expenditures ($ MM)1 Realized prices (includes hedges)3 Gas ($/Mcf) Liquids ($/Bbl) Production costs ($/Mcfe)4 Other taxes ($/Mcfe) General and administrative expenses ($/Mcfe) Total cash expenses5 June 2004 Forecast 810-860 $823 - - $0.66-$0.76 0.01-0.02 0.48-0.52 $1.15-$1.30 1Excludes discontinued operations 2Includes acquisitions 3Prices are stated after transportation costs 4Production costs include lease operating expenses plus production related taxes 5Cash expenses equal total operating expenses less DD&A and other non-cash charges 2004 Actual 814 $ 779 2 5.66 33.49 $ 0.71 0.00 $ 0.58 $ 1.29

Reserve Reconciliation Beginning balance 12/31/20031 Production Sale of reserves in place Purchases of reserves in place Extensions and discoveries3 Revisions Ending balance 12/31/20042 2,474 (298 ) (29 ) 64 141 (173 ) 2,181 Equivalent (Bcfe)4 1HH = $6.03/MMBtu, WTI = $32.52/Bbl 2HH = $6.22/MMBtu, WTI = $43.45/Bbl, Brent = $40.47/Bbl 3Includes EP shares of UnoPaso 4Approximately 82% of 12/31/2004 reserves are natural gas Note: Excludes discontinued operations and figures may not total due to rounding

PDP PDNP PUD 1262 285 634 Reserves Base PDP PDNP PUD 3092 669 998 $4.8 Billion PV10% 2,181 Bcfe PDP 3,092 65% PUD 998 21% PDNP 669 14% PDP 1,262 58% PDNP 285 13% PUD 634 29% Very high proportion of reserves are proved developed Note: Excludes discontinued operations

2004 Rig Activity Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Drilling 22 19 12 12 11 8 7 12 16 20 15 14 Completions 1 3 2 4 2 4 4 3 5 3 2 4 Recompletions 2 3 2 2 4 6 3 6 Workovers 1 1 1 1 1 1 3 1 3 2 1 Total drilling Total completions Total recompletions Total workovers 22 19 12 12 11 8 7 12 16 20 15 14 24 25 17 17 14 13 14 20 26 32 22 25 1st Half 2004 Capex: $331 MM 2nd Half 2004 Capex: $448 MM

2004 Capital by Region Texas Gulf Coast GOM/S. Lousiana Onshore International Acquisitions Other East 18 26 27 6 11 11 Total = $823 MM* Texas Gulf Coast 18% Int'l 6% Onshore 27% GOM 26% Other 12% June Forecast Total = $779 MM* Actual Acquisition 11% Texas Gulf Coast GOM/S. Lousiana Onshore International Acquisitions Other East 19 28 29 5 11 8 Texas Gulf Coast 19% Int'l 5% Onshore 29% GOM 28% Other 8% Acquisition 11% *Excludes discontinued operations

Capital Management System Value creation through the drill bit Strive for balanced program in each region Disciplined pre-drill evaluation Monthly post-drill analysis Continuously comparing post-drill evaluation to pre-drill assumptions Adjust program based on monthly results Managing Our Drilling Program

Capital Management System Ratio of present value of future cash flow discounted at 12% after tax to total investment CMS program includes drilling, leasehold and seismic costs Includes development drilling program Plan assumptions used beyond actual production and pricing Present Value Ratio as a Proxy for Value Creation

GOM TGC Onshore International Total 1H 0.36 1.04 1.37 0.35 0.82 2H 1 0.76 1.23 0.35 1.06 FY 0.92 Drilling Results Improving 1H 2H FY Note: Includes PUD development and new reserve additions; leasehold and seismic costs included Present Value Ratio & % of 2004 Drilling Capital 36% 26% 35% 3%

Region Performance Management Volumes: 800+ MMcfe/d Operating costs: $1.25-$1.40/Mcfe EBITDA: $1.1-$1.3 billion PVR: >1.15 Incremental program volume targets Finding costs: $1.40-$2.75/Mcfe 2005 Production Goals 2005 Drilling Goals

Lehman Acquisition $62.5 MM purchase price for 14 Bcfe Short life Quick payout Almost all proved producing Incremental interest in 86 operated wells High internal rate of return assured through hedging

2005 Plan Assumptions Capital $700 MM of capex $211 MM of acquisitions Hedges 132 TBtu at $6.90/MMBtu 60 TBtu puts at $6.00/MMBtu reflected in Marketing and Trading's results 4.6 TBtu at $7.31/MMBtu reflected in Marketing and Trading's results

Capital Allocation 2004 2005 Texas Gulf Coast 143 133 Onshore 244 501 Offshore 214 140 International 103 67 Corporate 75 70 Plan $779 $911 20041 20052 Texas Gulf Coast Onshore Offshore International Other3 1Includes acquisitions 2Includes Thorp acquisition of $32 MM and GMT acquisition of $179 MM 3Includes general, capitalized overhead, and interests for domestic operations Note: Excludes discontinued operations Higher PVR attracts more capital $179 MM E. Texas acquisition $32 MM S. Texas acquisition $ Millions

Production by Division Texas Gulf Coast Onshore Offshore International 283 231 276 24 2004: 814 MMcfe/d Onshore Texas Gulf Coast Onshore Offshore International 254 297 202 71 34% 24% 28% 36% 35% 31% 9% 3% 2005: 800+ MMcfe/d Texas Gulf Coast Onshore Texas Gulf Coast Offshore Offshore International International MMcfe/d Note: Excludes discontinued operations

Domestic Regions Texas Gulf Coast Closed $32 MM South Texas acquisition in January 2005 2005 Capital of $100 MM (excluding acquisition) Over 1/3 of capital plan targeting low risk production enhancement and recompletions 509 Bcfe proved reserves 5.8 R/P ratio* $1.41 billion pre-tax PV-10% Onshore Closed $179 MM East Texas acquisition in February 2005 2005 capital of $321 MM (excluding acquisition) Large inventory of low risk opportunities 1,196 Bcfe proved reserves 14.4 R/P ratio* $2.144 billion pre-tax PV-10% 2005 capital of $140 MM Re-aligned drilling program yields results West Cameron 75 Continued focus on recompletion program 261 Bcfe proved reserves 2.9 R/P ratio* $809 MM pre-tax PV-10% GOM *Based on January 2005 production annualized

Production Costs 2004 2005 Direct Lifting 0.6 0.56 Production Taxes 0.11 0.13 Other Taxes 0.01 0.02 Division G&A 0.22 0.23 Corporate G&A 0.35 0.31 Direct lifting Division G&A Production taxes Corporate G&A Other taxes $1.29/Mcfe $1.25-$1.40/Mcfe $/Mcfe Note: Excludes discontinued operations

2005 and 2006 Targets Production (MMcfe/d) Production costs ($/Mcfe)1 Other taxes ($/Mcfe) General and administrative expenses ($/Mcfe) Total cash expense2 2004 Actual 814 $0.71 0.00 0.58 $1.29 2005 Forecast 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 800+ $0.69-$0.78 0.01-0.02 0.54-0.61 $1.25-1.40 2006 Forecast 825+ $0.60-$0.70 0.01-0.02 0.49-0.58 $1.10-1.30

Other Non-Regulated

Non-Regulated Earnings Profile International Power Marketing & Trading 2004 2005 323 (545 ) 50-75 (100)-(75) *Adjusted for significant items (see page 16) Adjusted EBIT* ($ Millions)

Non-Regulated Goals Divest non-core assets Asia Power Central America Power Midstream operations Miscellaneous other Marketing and Trading Focus on managing equity natural gas and oil Continued roll-off of legacy book Opportunistically invest capital to reduce legacy transportation and other long-term transactions Brazil Power Resolve disputes Leverage asset base to support production operations

Regulated Overview

Regulated Business Premier North American pipeline franchise Deliver approximately 1/3 of total natural gas consumed in the U.S. Well positioned for growth Key business drivers Successful recontracting Prudent capital spending and operational efficiency Management of rate and regulatory issues Stable earnings and cash flow

Leading Natural Gas Infrastructure Mexico Ventures 106 miles; 2 Bcf/d Mojave Pipeline 400 miles; 0.4 Bcf/d El Paso Natural Gas 11,000 miles; 6 Bcf/d Colorado Interstate Gas 4,000 miles; 3 Bcf/d Wyoming Interstate 600 miles; 2 Bcf/d Cheyenne Plains Pipeline 380 miles; 0.6 Bcf/d ANR Pipeline 10,500 miles; 7 Bcf/d Great Lakes Gas Transmission (50%) 2,100 miles; 3 Bcf/d Tennessee Gas Pipeline 14,200 miles; 7 Bcf/d Elba Island LNG 4 Bcf Southern Natural Gas 8,000 miles; 3 Bcf/d Florida Gas Transmission (50%) 4,800 miles; 2 Bcf/d

Strategic Business Plan Near term (2005-2006) Manage value of existing capacity/contract positions Rate case completion FGT: January 2005 SNG: March 2005 EPNG: January 2006 CIG: October 2006 Prudent capital spending and cost control Manage capital spending on an average of $850 MM per year Continue to monitor and achieve O&M cost savings

Strategic Business Plan Long term Attach new supply Elba and Pipeline expansion (Cheyenne, Piceance) LNG and Deepwater in GOM (LA Deepwater Link) Mexico LNG and Bahamas LNG Blue Atlantic Add to strongest market positions Seafarer (Florida market) Northeast ConneXion (New England) Wisconsin expansions Shift weak positions to new markets ConneXion project (NY/NJ) Mexico expansions Pennsylvania and Ohio connections Optimally move short-term positions to longer term Major contract renewals (AGL, WE, SoCal, PSC, CSU)

New Centers of Demand Growth 6.0 7.2 8.0 Total 2003 73.8 2010 87.3 2015 98.1 NW and Alaska 14.5 15.5 16.7 4.0 5.0 5.6 2.7 2.9 3.4 5.3 7.5 8.5 Mexico Western Canada 10.9 11.4 12.2 Eastern Canada 3.3 3.4 3.7 9.3 11.2 12.3 Maritimes and Northeast U.S. 8.5 11.8 15.3 Bcf/d 4.2 4.4 5.1 5.1 6.9 7.4 8.5 11.8 15.3

Increased Supplies Driven by New Sources N.A. LNG Imports 2003 2010 2015 Western Canada Arctic 17.6 17.2 17.8 Rockies Mid- Continent Eastern Canada Mexico Gulf of Mexico West South Central 1.1 1.2 5.4 12.3 12.3 13.1 0.5 0.6 0.7 5.9 8.9 9.9 5.7 5.6 5.3 4.4 5.5 6.2 1.4 11.6 15.0 0.0 1.0 1.3 Alaska Mackenzie Bcf/d 18.4 17.5 17.2

Major Changes in Gas Flows 0.3 5.4 Arctic 0.7 2.7 0.6 7.3 0.3 1.4 0.6 0.6 0.1 N.A. LNG Imports 13.6 0.7 0.6 0.6 1.6 0.4 0.4 0.5 0.3 1.6 1.0 0.8 2.2 0.5 0.9 0.2 0.6 1.0 2003-2015 (Bcf/d)

LNG Impact on El Paso Opportunity Opportunity Opportunity Opportunity Neutral Neutral Neutral Negative Neutral Negative

LNG Related Growth Projects Blue Atlantic Pipeline Seafarer Pipeline $354 MM 2008 800 MMcf/d TGP/EPNG Sonora Project $TBD 2009 TBD MMcf/d TGP Distrigas $35 MM 2007 72 MMcf/d SNG Cypress Expansion $240 MM 2007 220 MMcf/d SNG Elba Island Expansion $157 MM 1Q 2006 3.5 Bcf Completed Projects FERC Certificated Signed PA's Future Projects

Major Growth Projects 0.6 0.5 0.2 Seafarer Pipeline $354 MM 2008 800 MMcf/d SNG North and South System $445 MM 2002-2003-2004 699 MMcf/d EPNG Line 2000 Power Up $136 MM June 2004 320 MMcf/d ANR Westleg $48 MM 2004 218 MMcf/d WIC Medicine Bow Expansion $58 MM 2007-2009 560 MMcf/d EPNG Cadiz to Ehrenberg (Line 1903) $74 MM December 2005 372 MMcf/d ANR Eastleg $17 MM 2005 142 MMcf/d TGP Northeast ConneXion New England $102 MM 2008 136 MMcf/d TGP Northeast ConneXion NY/NJ $24 MM 2006 41 MMcf/d ANR Northleg $13 MM 2005 110 MMcf/d WIC Piceance Lateral Expansion $120 MM December 2005 333 MMcf/d TGP Distrigas $35 MM 2007 72 MMcf/d EPNG Phoenix East Valley Line $49 MM September 2005 305 MMcf/d TGP LA Deepwater Link $28 MM April 2007 850 MMcf/d ANR Wisconsin 2006 Expansion $46 MM 2006 168 MMcf/d TGP/EPNG Sonora Project $TBD 2009 TBD MMcf/d WIC Mainline Expansion $63 MM 2007 198 MMcf/d TGP/ANR Supply Attachment Projects $113 MM 2005-2009 TGP LPG Reynosa $44 MM (50%) 2006 30,000 Bbl/d FGT Phase VII $63 MM May 2007 100 MMcf/d TGP/ANR Eugene Island 371 $14 MM April 2006 350 MMcf/d CIG Raton Basin Expansion $91 MM 2005-2008 175 MMcf/d Cheyenne Plains $416 MM 2004-2007 961 MMcf/d SNG Elba Island Expansion $157 MM 1Q 2006 3.5 Bcf SNG Cypress Expansion $240 MM 2007 220 MMcf/d Completed Projects FERC Certificated Signed PA's Future Projects

Financial Forecast EBIT EBITDA Growth 2005-2009 $ 1,317 $ 1,727 3%-5% $1,300-$1,350 $1,750-$1,800 $1,350-$1,450 $1,800-$1,900 2004 2005 2006 $ Millions

Capital Expenditure Forecast Maintenance Value added Subtotal capex Cheyenne Plains Total capex $424 493 $917 55 $972 $425 400 $825 - $825 2005 Average 2006-2009 2004 $ 463 271 $ 734 316 $ 1,050 $ Millions

2005 2006 2007 2008 2009 2010 Beyond TGP 1519 583 739 581 882 562 2391 ANR 1354 1994 566 721 395 1186 1395 EPNG 251 2658 1464 205 190 262 810 CIG 558 587 1567 146 165 103 2905 SNG 155 592 204 511 190 453 1489 Contract Portfolio 13% 3,838 21% 6,414 15% 4,539 7% 2,164 6% 1,821 8% 2,566 30% 8,989 Average remaining contract term: 4.5 years Thousands of Dth/d TGP ANR EPNG CIG SNG Contract Expiration Portfolio

Successful Recontracting SNG: AGL (926 Mdth/d) EPNG: SoCal Gas (768 Mdth/d) TGP: Southeast (271 Mdth/d) Northeast (716 Mdth/d) ANR: Michcon (220 Mdth/d) WE Energies (65 Mdth/d) CIG: Colorado Springs Utilities (298 Mdth/d)

Summary Providing value through performance Safe, efficient, and dependable delivery service Focus on operational efficiency Capturing value today Successful rate cases Continue progress on recontracting Risk management Continue cost control Building value for tomorrow Strategic market expansions and supply additions Optimize contract portfolios 2005-2009 Growth at average rate 3%-5%

Summary El Paso making good progress on all fronts Success in 2005 measured by: Position company to generate meaningful free cash flow Completing turnaround of production business Meeting $15 billion net debt target Further cost reduction

Q&A

Regional Pipeline Presentations

Eastern Pipelines

El Paso Eastern Pipeline Group Great Lakes Gas Transmission (50%) 2,100 miles; 3 Bcf/d ANR Pipeline 10,500 miles; 7 Bcf/d Tennessee Gas Pipeline 14,200 miles; 7 Bcf/d Mexico Ventures (50%) 106 miles; 2 Bcf/d Focusing on Challenges & Opportunities

Eastern Pipelines Longline Pipelines... Multiple regions Highly differentiated markets Diverse customer base ...Going from the right places to the right places Unmatched supply connections Well positioned for LNG Growth Strong market franchises ...Highly competitive corridors

Franchises and Battlegrounds Franchise Market Battleground Market "Upgrade" Market WI MI OH IL/IN SW SE Citygate/Direct 1655 1182 362 574 247 217 Pipelines 27 969 989 633 6 565 ANR Market Connectivity (Contract MDth/d) Citygate/Direct Pipelines Zn 0 Zn 1 Zn 2 Zn 3 Zn 4 Zn 5 Zn 6 Citygate/Direct 416 663 117 25 308 752 1541 Pipelines 25 1005 63 276 1139 285 168 Citygate/Direct Pipelines TGP Market Connectivity (Contract MDth/d)

Strategic Business Plan Optimize transportation and storage portfolio Optimize first-mile and last-mile connections Enhance mainline connectivity Aggressively attach new supply sources Focus on operational efficiencies Continuous risk management focus

Major Growth Projects ANR Westleg $48 MM 2004 218 MMcf/d ANR Eastleg $17 MM 2005 142 MMcf/d ANR Northleg $13 MM 2005 110 MMcf/d ANR Wisconsin 2006 Expansion $46 MM 2006 168 MMcf/d TGP Northeast ConneXion New England $102 MM 2008 136 MMcf/d TGP Northeast ConneXion NY/NJ $24 MM 2006 41 MMcf/d TGP Distrigas $35 MM 2007 72 MMcf/d TGP LA Deepwater Link $28 MM April 2007 850 MMcf/d TGP/ANR Eugene Island 371 $14 MM April 2006 350 MMcf/d TGP/ANR Supply Attachment Projects $113 MM 2005-2009 Mexico JV- LPG Reynosa $44 MM (50%) 2006 30,000 Bbl/d Mexico JV - Sonora Lateral $TBD 2009 TBD MMcf/d Completed Projects FERC Certificated Signed PA's Future Projects

Contract Portfolio TGP ANR 2005 2006 2007 2008 2009 2010 Beyond TGP 1519 583 739 581 882 562 2391 ANR 1354 1994 566 721 395 1186 1395 TGP & ANR Capacity 13,500 2,873 2,577 1,305 1,302 1,277 1,748 3,785 Thousands of Dth/d Contract Expiration Portfolio

Summary Franchise areas growth with focused capital spending Mainline corridor values enhanced with supply push and connectivity pull Managing contract portfolio to capture opportunities Poised to benefit from major market trends

Western Pipelines

Western Pipelines Systems Mojave Pipeline 400 miles; 0.4 Bcf/d El Paso Natural Gas 11,000 miles; 6 Bcf/d Colorado Interstate Gas 4,000 miles; 3 Bcf/d Wyoming Interstate 600 miles; 2 Bcf/d Cheyenne Plains Pipeline 380 miles; 0.6 Bcf/d

Strategic Business Plan Near Term (2005-2006) Maximize value of existing capacity through successful re-contracting on EPNG and CIG Systems Rate Case effective dates EPNG January 2006 Potentially pre-settle with EPNG customers on major cost of service issues CIG October 2006 Continue to develop good customer relationships Prudent capital spending and cost control Complete announced expansion projects

Strategic Business Plan Long term Attach/transport new supply Add to strongest market positions Shift weak positions to new markets Control costs

Contract Portfolio 2005 2006 2007 2008 2009 2010 Beyond EPNG/Mojave 251 2658 1464 205 190 262 809 CIG/WIC/CP 558 587 1567 146 165 103 2905 Thousands of Dth/d EPNG/Mojave & CIG/WIC/CP Capacity 11,600 EPNG/Mojave CIG/WIC/CP 809 3,245 3,031 351 355 365 3,714 Contract Expiration Portfolio

Successful Recontracting EPNG: SoCal Gas (768 Mdth/d)-Expires 2009-2011 Renewal of 98% of EPNG's current contract for SoCal's core market CIG: Colorado Springs Utilities (298 Mdth/d)-Expires 2006-2017

Major Growth Projects WIC Medicine Bow Expansion $58 MM 2007-2009 560 MMcf/d EPNG Phoenix East Valley Line Up to $49 MM September 2005 305 MMcf/d WIC Mainline Expansion $63 MM 2007 198 MMcf/d EPNG Sonora Project $TBD 2009 TBD MMcf/d EPNG Line 2000 Power Up $136 MM June 2004 320 MMcf/d Cheyenne Plains $416 MM 2004-2007 961MMcf/d EPNG Cadiz to Ehrenberg (Line 1903) $74 MM December 2005 372 MMcf/d WIC Piceance Lateral Expansion $120 MM December 2005 333 MMcf/d CIG Raton Basin Expansion $91 MM 2005-2008 175 MMcf/d Completed Projects FERC Certificated Signed PA's Future Projects

Summary Managing re-contracting and rate cases to maximize capacity values Implementing array of solid expansion projects Well positioned for additional growth in the Rockies Growing new market opportunities (growth in Arizona and Mexico, and Sonoran LNG) offset potential capacity turnback on EPNG

Southern Pipelines

Southern Pipelines Elba Island LNG 4 Bcf Southern Natural Gas 8,000 miles; 3 Bcf/d Florida Gas Transmission (50%) 4,800 miles; 2 Bcf/d

Southern Pipelines Solid demand growth Strong market position Concentrated customer base Distribution-like systems Competitive advantage Rate cases FGT just completed rate case settlement SNG in settlement discussions now Fully subscribed

Contract Portfolio 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr East 20.4 27.4 90 20.4 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Thousands of Dth/d SNG1 FGT 2005 2006 2007 2008 2009 2010 Beyond SNG 155.286953 592.135076 203.551665 511.175902 190.108158 452.923768 1489.556299 FGT 4.436 12.512 9.87 4.261 240.077 259.501 1494.591 FGT Capacity 2,200 SNG Capacity 3,400 Contract Expiration Portfolio Comment: AGL recently agreed with SNG to extend 926 MDth/d for average of 6 years 1Includes AGL Contract extensions

Major Growth Projects SNG North and South System $445 MM 2002-2003-2004 699 MMcf/d SNG Elba Island Expansion $157 MM 1Q 2006 3.5 Bcf SNG Cypress Expansion $240 MM May 2007 220 MMcf/d FGT Phase VII $63 MM May 2007 100 MMcf/d Seafarer $354 MM 2008 800 MMcf/d Completed Projects FERC Certificated Signed PA's Future Projects

Cypress Project Elba Island JEA FPC (Progress) Supported by 20-year Agreements with BG LNG Services & Progress Energy FL Cypress Project 165 miles of 24" pipe Capacity: 220 MMcf/d Capex: $240 MM FERC filing 2Q 2005 In-service May 2007 FGT Phase VII Capacity: 100 MMcf/d Capex: $63 MM In-service May 2007

Strategic Business Plan Near term (2005^2006) SNG rate case settlement With contract extensions Elba expansion: On time/on budget Cypress: FERC certificate, then construction Long term Use LNG from Elba and Bahamas to capitalize on growing markets in the Southeast

Q&A

Major Growth Projects 0.6 0.5 0.2 Seafarer Pipeline $354 MM 2008 800 MMcf/d SNG North and South System $445 MM 2002-2003-2004 699 MMcf/d EPNG Line 2000 Power Up $136 MM June 2004 320 MMcf/d ANR Westleg $48 MM 2004 218 MMcf/d WIC Medicine Bow Expansion $58 MM 2007-2009 560 MMcf/d EPNG Cadiz to Ehrenberg (Line 1903) $74 MM December 2005 372 MMcf/d ANR Eastleg $17 MM 2005 142 MMcf/d TGP Northeast ConneXion New England $102 MM 2008 136 MMcf/d TGP Northeast ConneXion NY/NJ $24 MM 2006 41 MMcf/d ANR Northleg $13 MM 2005 110 MMcf/d WIC Piceance Lateral Expansion $120 MM December 2005 333 MMcf/d TGP Distrigas $35 MM 2007 72 MMcf/d EPNG Phoenix East Valley Line $49 MM September 2005 305 MMcf/d TGP LA Deepwater Link $28 MM April 2007 850 MMcf/d ANR Wisconsin 2006 Expansion $46 MM 2006 168 MMcf/d TGP/EPNG Sonora Project $TBD 2009 TBD MMcf/d WIC Mainline Expansion $63 MM 2007 198 MMcf/d TGP/ANR Supply Attachment Projects $113 MM 2005-2009 TGP LPG Reynosa $44 MM (50%) 2006 30,000 Bbl/d FGT Phase VII $63 MM May 2007 100 MMcf/d TGP/ANR Eugene Island 371 $14 MM April 2006 350 MMcf/d CIG Raton Basin Expansion $91 MM 2005-2008 175 MMcf/d Cheyenne Plains $416 MM 2004-2007 961 MMcf/d SNG Elba Island Expansion $157 MM 1Q 2006 3.5 Bcf SNG Cypress Expansion $240 MM 2007 220 MMcf/d Completed Projects FERC Certificated Signed PA's Future Projects

Review of Production Regions

Gulf of Mexico (GOM)/ South Louisiana (SLA)

GOM/SLA Position GOM Position Total El Paso HBP El Paso Op HBP Other Op Leases 238 79 66 Blocks 222 77 66 El Paso Operated Structures 102 SLA Position Acres Leased 17,000 Acres Optioned 202,300 1/05 Production Volumes Actual 246 MMcfe/d 1/1/05 Net Proven Reserves 261 Bcfe 2005 Reserve / Production Ratio 2.9

GOM Industry Comparison* Apache Newfield Devon El Paso Chevron Hunt Spinnaker Forrest Kerr McGee BP Remmington Magnum Hunter Noble BHP Pioneer Gryphon Bois d'Arc Houston Exploration Unocal Dominion Designated Operated Blocks 154 115 103 103 99 92 89 88 84 81 78 69 67 62 62 62 53 49 46 43 Operated Blocks *Designated as operator of shelf offshore block

GOM/SLA Production Profile 7/1/2004 8/1/2004 9/1/2004 10/4/2004 11/4/2004 12/4/2004 1/1/2005 2/1/2005 3/1/2005 4/1/2005 5/1/2005 6/1/2005 7/1/2005 8/1/2005 9/1/2005 10/1/2005 11/1/2005 12/1/2005 1/1/2006 2/1/2006 3/1/2006 4/1/2006 5/1/2006 6/1/2006 7/1/2006 8/1/2006 9/1/2006 10/1/2006 11/1/2006 12/1/2006 Base 259 244 209 214 214 211 191 178 167 162 152 129 123 117 110 98 92 87 83 78.9 74.9 71.2 67.6 64.2 61 58 55.1 52.3 49.7 47.2 04CAP 0 0 0 0 13 24 27 24 23 20 18 20 19 21 20 37 35 34 33.2 31.4 29.7 28.4 26.9 25.6 24.2 22.7 21.5 20.3 19 17.4 05DRLG 0 0 0 0 0 0 0 0 7 14 13 28 29 33 38 40 39 46 43.5 42.2 40.8 39.4 38.1 37.2 35.4 33.4 35.6 34.3 32.9 35.1 05REC 0 0 0 0 0 0 0 0 2 6 12 12 17 22 32 40 42 51 56 56 56.1 52.6 50.3 47.8 44.5 41.7 39.2 36.8 34.3 32.3 06CAP 6 10 16 21 26 31 36 41 46 51 58 Volumes stable at 200 MMcfe/d on $150 MM capital per year Base 04 CAP 05 DRLG 05 REC 06 CAP Hurricane Ivan Net MMcfe/d

Production Enhancements Add Stability 2004 Base Volumes Drilling Volumes Workover Volumes Recompletion Volumes 2005 Plan Recompletions 66 Total Projects $40 MM Cost 19 MMcfe/d Net Rate 2004 2005 Hurricane Ivan 2004 Recompletions: 39 MMcfe/d 2004-2005 Increase 59 Total Projects $31 MM Cost Net MMcfe/d 2004 Workovers: 53 MMcfe/d 2004-2005 Increase 97 Total Projects $15 MM Cost

GOM/SLA 2004 Drilling Schedule Total Dry Hole Cost $60.5 MM $60.5 MM dry hole costs in deep shelf with average TD 19,712' Mid year refocus in program 2nd Half: 7 successful wells with average TD 11,185' Results from wells booked in 2nd Half 1.0 PVR; with all costs FY 2004: $50.7 MM drilling cost for 9 total successful wells

2005 GOM Drilling Program HI 48 WC 62 #2 OBOC GA 151 B-2 WC 504 B-9 VK 385 WC 95 #2 OBOC MC 151 WC 62 #1 WC 95 #1 WC 504 B-3 WC 75 HI 115 OBOC VK 823 Wells 6 EXPL 7 DEV Avg MD 17,118' 12,338' 14,727' Net P10 141 25 166 Net RM* 25 14 39 Capital($ MM) 34 20 54 Reserves (Bcfe) Gross Ps 57% Net Ps 67% *Risked mean reserves

2005: Balanced Drilling Program 0-12,000' 12-16,000' 16-22,000' East 21747 17279 15502 West 30.6 38.6 34.6 North 45.9 46.9 45 0-12,000' 12-16,000' 16,000'+ Total: $54 MM 4 Wells HI48 Cris R WC95 2 Marg A WC62 Marg A VK385 A-4 6 Wells WC504 B-3 ST (Drilled) WC504 B-9 (Drilling) WC95 1 Cris A GA151 B-2 (OBOC) MC151 (OBOC) VK823 (OBOC) 3 Wells WC75 Discovery WC62 HI 115 ST Development $15,502 28% $21,747 40% $17,279 32%

GOM Lower Miocene Trend with Recent Discoveries Average Top of Reservoir (TVD): 14,352' Average Initial Production (MMcfe/d): 26

WC 75 Discovery Pay Sand El Paso WC 75 #1 Discovery Well

West Cameron 62 Exploration Well WC 62 Target WC 75 Pay Sand WC 75 Discovery WC 62 Exploratory Surface Location 62 75 A A'

2005 South Louisiana Program Little Bay Liberty Canal Cane Ridge Long Point Clear Lake Mound Point North Kaplan S. Cameron Canal W. Mulvey Bancker Carried Prospects El Paso Operated Wells 6 at 25% Carry 4 at 50% WI* Avg MD 19,083' 14,125' 17,100' Net P10 160 25 185 Net RM 13 10 23 Ps(%) 19-36 65-86 Reserves (Bcfe) *Promoted 1/3 for a 1/4

South Louisiana: Moderate Risk Program 0-12,000' 12-16,000' 16-22,000' East 4 2 4 West 30.6 38.6 34.6 North 45.9 46.9 45 0-16,000' 16-18,000' 18,000'+ Total DHC $5.8 MM 25% Carry to casing point 4 wells $0 0% 4 wells $5,799 100% 2 wells $0 0%

South Louisiana: Deep Drilling Carry Currently drilling Little Bay Prospect, 22,000' well In Achafalaya Bay National Wildlife Refuge, St. Mary Parish, Louisiana Lower Miocene objectives (Rob series) El Paso carried for 25% W.I. to casing point El Paso recouped $1.66 MM sunk costs Currently negotiating 7+ Additional prospects 16,500'-22,000' wells $50 MM-$100 MM drilling commitment El Paso carried for a 25% W.I. to casing point El Paso recoups minimum $6.5 MM sunk cost AMI's prospect specific, no large scale AMI Potential to expand program into Offshore GOM

South Louisiana Planned Drilling Prospect "A" UO-2 Sand UO-2 UO-1 LM-1 Prospect "A" Type Log

2005 Capital Detail Seismic Abandonment Leasing Equipment Recompletions Drilling East 4005 10000 2500 16762 40300 55959 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Seismic 3% Abandonment 8% Leasing 2% Equipment 13% Recompletions 31% Drilling 43% Seismic Abandonment Leasing Equipment Recompletions Drilling East 1000 0 5004 1132 0 3524 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 GOM: $130 MM SLA: $11 MM Drilling 33% Seismic 9% Equipment 11% Leasing 47%

Cost Control Labor Transportation Equip, Main, & Sup. Gross Workover Compression Other East 20 19 20 18 8 15 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Labor 20% Transportation 19% Equipment 20% Workover 18% Compression 8% Other 15% Divest high cost assets Maintain focused coordination of transportation Implement reduced spending plan for workovers, equipment, maintenance and supplies for planned divestments Competitively bid helicopter transportation and chemicals for 2005 Convert contractors to permanent employees in core assets 2005 Initiatives

GOM/SLA Summary Drill a medium risk and depth prospect portfolio with solid PVR Perform recompletions and workovers that stabilize base production Control costs while maintaining production, EH&S, and Regulatory Compliance Divest or abandon high LOE properties

Texas Gulf Coast (TGC)

Texas Gulf Coast 771 producing wells (including recent south Texas acquisition) January production: 243 MMcfe/d Year-end 2004 reserves: 510 Bcfe R/P Ratio: 5.8

Texas Gulf Coast 2004 drilling program did not meet economic hurdles Improved prediction of probability of success Overestimated reserves Largely exploration driven 2005 focus will be on re-building a balanced inventory Continue focus on production issues and enhancements

Texas Gulf Coast Production Profile 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr East 20.4 27.4 90 20.4 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Net MMcfe/d 2004 Base 2005 Program 2006 Program 2005 production challenged by 2004 results

Texas Gulf Coast 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 5/31/2004 6/30/2004 7/31/2004 8/31/2004 9/30/2004 10/31/2004 11/30/2004 12/31/2004 1/31/2005 MMCFE/D 99.404 88.358 85.249 84.206 79.378 74.197 69.876 67.3 63.551 59.328 59.815 57.727 56.616 52.705 50.229 48.814 47.893 45.35 43.149 43.544 40.277 38.883 39.54 1 Qtr Forecast MMCFE/D 39.957 38.428 37.352 36.517 BASE DECLINE 98.7 92.7 87.2 82.1 77.4 73.1 69 65.3 61.8 58.5 55.5 52.6 49.9 47.4 45.1 42.9 40.8 38.9 37 35.3 33.689 32.152 30.707 821 728 653 610 Base Decline Production Uplift 8.8 MMcfe/d 147 Projects on 124 wells resulting in an incremental gross 2.3 Bcfe for 2004 and current production uplift of 8.8 MMcfe/d Total cost $9.1 MM gross 54 plungers 57 CT CO 8 gas lift 18 misc. Note: Production history and decline is only from 124 wells Base Impact Production MMcfe/d Production Enhancement Projects

Cost Control Initiatives Labor Chemicals SWD Other Workovers Compression easy 9.709 7.142 3.343 10.956 4.904 18.822 Compression 18.8% Labor 9.7% Chemicals 7.1% Other 10.9% SWD 3.3% Workovers 4.9% Assigned full time engineer/supervisor to manage compression optimization and maintenance Add one (1) SWD facility and expand another Convert contract positions to full time company employees in core, long life fields Chemical treating awarded to one provider across the division (15% cost reduction) Conduct root cause analysis on recent mechanical failures 2005 Initiatives

26 producing wells Current production rate: 8.0 MMcfe/d (net) Operating cost synergy Opportunities to apply artificial lift technology Improved processing margin South Samano Field Acquisition Samano South Samano

Vicksburg Prospects Map Area Kimber Prospect WI = 50% First production: Jan. 2005 Current rate: 2.2 MMcfe/d TD: 21,243' Santa Fe Ranch North Monte Christo Other Vicksburg Leads & Prospects

Upper Gulf Coast-Frio Prospects Other Frio Leads & Prospects Expanded Wilcox Vicksburg Frio Mad Island Prospect WI = 50% First production: April 2005 (estimate) Current status: Laying flow line TD: 21,000'

"The Beast" Merged 3D Leads The Beast 3D Outline Leads Vicksburg Production Frio Production Yegua Production Merged volumes: August 2004 1st Phase Recon: 60 Leads 50/50 Frio/Vicksburg Depths: 4,000'-15,000'; Avg: 9,500' Acres: 100-1,700; Avg: 400

2005 Capital Program Production Capital Leasing Seismic Proved Drilling Non-Proved Drilling East 33.5 7.1 3.4 10.2 45.8 Production Capital 33.5% Leasing 7.1% Seismic 3.4% $100 MM Drilling Proved 10% Drilling Non-Proved 46%

2005 Program Emphasis Improve pre-drill estimates Adjust drilling program to meet economic goals Continue focus on production optimization Reduced drilling program in 2005 Root cause analysis of mechanical failures Bring "Beast" 3D AVO leads to prospect status

Onshore

Onshore Regional Statistics Onshore: Raton 65 MMcfe/d1 376 Bcfe proved reserves 15.8 R/P ratio Onshore: Rockies 21 MMcfe/d1 106 Bcfe proved reserves 13.8 R/P ratio Onshore: Arkoma 15 MMcfe/d1 84 Bcfe proved reserves 15.3 R/P ratio Total Onshore 255 MMcfe/d1 1,243 Bcfe proved reserves 13.4 R/P ratio Onshore: Arklatex2 93 MMcfe/d 394 Bcfe proved reserves 11.6 R/P ratio Onshore: Black Warrior 61 MMcfe/d1 283 Bcfe proved reserves 12.7 R/P ratio 1January 2005 2Production and reserves reflect East Texas acquisition impact

Onshore Production Profile Capital Program yields 40% volume growth in 2005 2005 Base 2005 Drilling 2005 Recompletions 2005 Acquisition 2006 Program

2005 Onshore Capital Drilling (Proved) Drilling (Non-Proved) Recompletions Equipment Leasing & Seismic Onshore 137 98 35 45 7 $321 MM Arkoma Black Warrior Raton Rockies Arklatex Onshore 40 58 84 38 100 Basin Allocation Drilling (Proved) 43% Drilling (Non-proved) 30% Recompletions 11% Equipment 14% Leasing & Seismic 2% Arkoma 13% Black Warrior 18% Raton 26% Rockies 12% Arklatex 31% Excluding Acquisition Capital

Cost Control Initiatives Power & Fuel Compression Water Disposal Equip. Maintenance Labor Workovers Chemicals Other East 14503 10711 8971 9097 8498 5559 3709 12572 2005 Initiatives Lower unit expenses 18% over 2004 level Expand water disposal capabilities Expand operating routes with efficiency improvements such as pump off controllers Replace existing rental compression with company owned machines Targeted program to address high cost Altamont producers Expand control of compressor maintenance Power & Fuel 19% Compression 15% Water Disposal 12% Equip. Maint. 12% Labor 12% Workovers 8% Chemicals 5% Other 17%

Raton Performance 3Q02 4Q02 1Q03 2Q03 3Q03 4Q03 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 Actual 38.6 40.2 45 45.7 45.8 50.2 54 55.6 61.1 64.6 2005 Plan 72.7 75.2 78.3 81.2 Actual 2005 Plan

Raton Horizontal Completions 13 completed/in-progress Combined 144% increase in production Testing horizontal laterals from existing vertical well bores and new wells Sufficient lateral length is achievable on current spacing Incremental lift efficiency derived from vertical well bore "sump" Will test "stacked" multi- laterals in 2005 Raton Coals Vermejo Coals

Raton Horizontal VPR "D" #6 (Converted From Vertical to Horizontal-August 2004

Vertical Completions Horizontal Completions at year-end 2005 Horizontal Wells 10 horizontal completions at year-end 2004 30 to be tested in 2005 Raton/Vermejo Park Ranch

Raton Refracs Targeting Wells completed with older technology frac fluids Thin stacked coal seams Eleven wells re-fractured in 2004 Average 50% production increase Gross Mcf/d VPR "D" #4 (Re-fractured February 2004)

Projected Raton Program through 2008 Producing Well Proposed 2005 Proved Location Future Location Future Location Non-Commercial CBM

Uinta Powder River Wind River Washakie Raton Green River San Juan Paradox Denver Williston Big Horn Piceance Rockies 2004 Summary Anadarko/Big George and Big Mike Units (19% WI) 117 producing wells 2005 Drilling: 70 wells Net production: 4 MMcf/d Mallard Exploration Test (50% WI) Tested 2.5 MMcf/d 1st sales anticipated March 2005 Antelope-Mesa Exploration Test (25% WI) Tested 2 MMcf/d: 1st sales anticipated 3Q2005 Decision on 2nd well pending production results Altamont Bluebell 8 Recompletions $3.5 MM Current rate uplift 590 bopd 20 Enhancement projects $3.1 MM Current rate uplift 350 bopd

Altamont Production Enhancement 20 Projects 350 BOE/D Uplift $3.1 MM 10 pump conversions 6 downhole repairs Re-establish production from previously abandoned zones (4)

Arklatex Locator Map Map Area Shongaloo Field Sibley / Ada / W. Bryceland Fields Holly / Bethany- Longstreet Fields Minden Field Stockman Field Bear Creek Field

2Q03 3Q03 4Q03 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 Actual 0.855 2.135 3.836 7.245 11.987 15.109 17.03 Plan 20.9 24.3 29.8 37.6 East Texas Acquisition 52 producing wells (45 operated) 12,500 net acres 85% production growth in 2005 Long-life assets 10.4 proved R/P Large inventory 70 PUD locations 154 future locations Low lifting cost: $0.33/Mcfe Highlights Minden Field Actual Plan

Minden Field 2005 drilling program 38 wells* (27 PUDs) 2 rigs with 3rd rig in 2nd quarter $54.8 MM* 2005 recompletions $1.4 MM Focused analysis of secondary opportunities Low resistivity pay Travis Peak Pettit Operated Wells 2005 Locations Future Locations *January 1, 2005 Upper Cotton Valley Gross reserves: 1.1 Bcfe Average well cost: $1.4 MM Average depth: 10,800'

Onshore Summary Large inventory of consistent low risk opportunities for 2005 and beyond Anticipate significant volume growth in 2005 Focus on cost control and production optimization

International

International Division New integrated international division Brazil defined as a business unit Combined power and E&P Selectively build on current E&P position in Brazil Growth strategy founded on: Detailed technical and commercial analysis Disciplined economic and risk evaluations

Brazil: A Balanced Mix of Exploration and Development Exploration Blocks Production Blocks Camamu/Almada Basin Development/Appraisal: BM-CAL-4 (Cavala, Canapu fields) and Sardinha fields Exploration Upside: BM-CAL 5, 6, 372 and 312 Potiguar Basin Production: Pescada-Arabaiana Fields Exploitation: RNS 33, 93 and 128 Exploration Upside: BPOT-11 & 13 Espirito Santo Basin Exploration: BM-ES-5 Santos Basin Development/Appraisal: Lagosta Field

Steadily Developing a Material Position # Blocks Currently the 2nd largest IOC acreage holder in Brazil Area Production and development opportunities Pescada-Arabaiana Lagosta Camamu, Canapu, and Sardinha Acreage acquired by bid round* *After relinquishments

Leading Producer in Brazil 1.8 MM BOE/D El Paso based on 2005 plan Other companies data based on Wood MacKenzie Petrobras Shell El Paso Queiroz Galvao Northern Oil Repsol-YPF PETROPAR PetroSantander Starfish Koch Petroserv Anadarko 46 12 9 4 4 3 3 1 1 1 0

PNP 33% PUD 20% PDP 47% Brazil Portfolio Growth 2004 Proved Reserves: 214 Bcfe 68% Oil + 32% Gas PDP 18% PUD 67% PNP 15% 2003 Proved Reserves: 123 Bcfe PUD 100% 2004 Reserves purchase: 49 Bcfe (50% UnoCal acquisition) Reserves reclassification: 49 Bcfe (50% UnoPaso) Less Production/Revisions 7 Bcfe

Gas Oil East 79 21 Moving to An Oil-Weighted Portfolio oil gas oil 68 32 2005 Production: 71 MMcfe/d 2004 Reserves: 214 Bcfe Oil 21% Gas 79% Gas 32% Oil 68%

Brazil Production Profile Net MMcfe Pescada- Arabaiana Reversion Proved Probable Exploration Upside Note: Proved = Pescada + Camamu Probable = Lagosta + Horizontal Exploration Upside = BPOT 13 + CAL 5 & 6 + Cal M 312 & 372 + ES 5 10% CAGR

2005 Capital Program By Projects By Category Exploration (29%) $58 MM Firm 63% Committed 28% Contingent 9% Production and Development 55%

BM-POT-11 and 13 Exploration Upside Oil and gas leads Oil and gas leads Offshore^Avg. W.D. 50 meters EP (UnoPaso) 35% working interest Petrobras operated 79% revenue interest until payout Acquisition: 2001 Petrobras and 2004 Unocal Gas sold to Petrobras (take or pay)

Pescada/Arabaiana-Ahead of Plan Increment realized over projection Projected at acquisition date Net Production (Mcfe/d) Aug 2004 Sep 2004 Oct 2004 Nov 2004 Dec 2004 50,800 50,800 50,800 50,800 50,800 4,588 4,223 7,088 4,861 8,493 55,388 55,023 57,888 55,661 59,293

Santos Basin: Lagosta Merluza Field Lagosta Field W E Current Status W.D. 200 m WI: EP (60%), BR (40%) Net 50 Bcfe (unbooked) GSA negotiations with Petrobras Plan of development due to ANP by mid March 2005 Analyzing combined development: Merluza/Lagosta

Canapu Field CAL-M-312 CAL-M-372 BM-CAL-5 BM-CAL-6 Camamu Production and Exploration Potential Block Consortium BM-CAL-4 EP* (100%) BM-CAL-5/6 BR* (45%) EP (18.3%) QG (18.3%) PS (18.3%) CAL-M-312/372 BR* (60%) EP (20%) QG (20%) Sardinha EP* (40%) BR (40%) IP (20%) Ilheus Salvador Camamu Refinery Cavala Field Sardinha Field BM-CAL-4 BM-CAL-4 Status Finalizing 3D interpretation Pre-feed study on high pour-point oil BM-CAL 5/6 Status Finalizing 3D interpretation 2 wells will be drilled on BM-CAL 5/6

Copaiba Prospect Amplitude Ribbons MDB objective Deepwater Camamu Basin 77 Copaiba prop. loc. Expected spud 2nd Half 2005

BIA-1 Recent 450 MMBO+ light oil discovery Esp^rito Santo Basin Exploration Offshore^Avg. W.D. 650 m EP (UnoPaso) 35% WI Petrobras operated

Brazil Summary Short-term production growth from development projects Horizontal oil well at Pescada Development of Camamu Basin oil UnoPaso acquisition outperforming plan Analyzing Bid Round 7 potential and strategic fit

Review of Other Non-Regulated

Power

2004-2005 Power Plant Sales Status Contracted power plants 26 plants closed Merchant power plants 6 plants closed 4 plants targeted to close by 6/30/2005 Restructured contract assets Mohawk River Funding IV closed Utility Contract Funding closed CBI and CBII closed Total $749 83 2 5 21 (134 )* 726 Proceeds Debt Removed *Includes equity distributions paid to El Paso and elimination of trading positions $171 75 815 575 1,636 Domestic Power $ Millions

Remaining Domestic Power Plants Power plants Midland Cogeneration Ventures Berkshire Restructured contract assets Mohawk River Funding II Expect sale of most remaining domestic assets by end of 2005

Current Profile of International Power Assets South America Central America and Europe Asia Total Number of plants Number of pipelines 1,816 574 2,097 4,487 30 2 Net MW 2004 Reported EBIT $ 69 12 (215 ) $ (134 ) 15 countries 3,690 km 2004 Earnings from Ops. $ 236 24 61 $ 321 $ Millions Note: Not adjusted for sale of PPN in March 2005

Brazil Power Bolivia-to-Brazil Pipeline 2004 Throughput: 722 BBtu/d Ownership: 8% Porto Velho (404 MW) Ownership: 50% Argentina-to-Chile Pipeline 2004 Throughput: 77 BBtu/d Ownership: 22% Rio Negro (158 MW) Ownership: 100% Manaus (238 MW) Ownership: 100% Macae (928 MW) Ownership: 100% Araucaria (484 MW) Ownership: 60% Gross MW

Brazil Power Update Macae Petrobras minimum revenue payments end in August 2007 Petrobras ceased making payments in January 2005 and has filed for arbitration Manaus/Rio Negro Two PPAs with Manaus Energia, S.A. through January 2008 Porto Velho Two PPAs with Eletronorte expiring in 2010 and 2023 PPA amendments being discussed Araucaria One PPA with Copel expiring in 2022 Project has filed an international arbitration due to non-payment by off-taker

Marketing & Trading

MTM Trade Book Value by Commodity Portfolio value Natural gas Power/Cross commodity Cordova Subtotal Production hedges Cedar Brakes I & II and hedges Put options Total $ (165 ) 180 (30 ) $ (15 ) (376 ) (97 ) - $ (488 ) December 31, 2003 September 30, 2004 $ (16 ) 142 (49 ) $ 77 (630 ) (199 ) - $ (752 ) $ (83 ) 175 (13 ) $ 79 (484 ) (120 ) - $ (525 ) March 31, 2004 $ (21 ) 85 (23 ) $ 41 (536 ) (131 ) - $ (626 ) June 30, 2004 *On 12/1/2004 205 TBtu of positions were moved into the hedge book; the value of the positions on 12/1/2004 was $(592) MM December 31, 2004 $ (19 ) 127 (49 ) $ 59 - * (240 ) 120 $ (61 ) $ Millions

Marketing and Trading EBIT MTM change in FMV Legacy trade book Legacy production hedges Production puts Demand charges Settlements Early terminations Gross margin Operating exp/other inc Reported EBIT $ 20 (156 ) - (35 ) 12 - $ (159 ) (13 ) $ (172 ) March 31, 2004 $ (5 )1 (104 ) - (40 ) 8 - $(141 ) (11 ) $ (152 ) June 30, 2004 $ (22 ) (143 ) - (39 ) 15 69 2 $(120 ) (18 ) $ (138 ) September 30, 2004 $ (70 ) (36 ) 53 (37 ) 4 (2 ) $ (88 ) 3 $ (85 ) December 31, 2004 Quarter Ended 1Includes $69 MM that represents the accrual for the Western Energy settlement contract revaluation 2$50 MM gain for final cash installment on Elba Island asset sales, $24 MM gain on sale of Newark Bay and $(5) MM loss for power trade terminations $ (77 ) (439 ) 53 (151 ) 39 67 $ (508 ) (39 ) $ (547 ) 12 Months Ended Dec. 31, 2004 $ Millions

Marketing and Trading EBIT Targets 2004 reported EBIT Less: Production hedges and puts Less: Change in FMV & terminations Less: One-time severance expense 2004 adjusted EBIT 2005 EBIT target 2006 EBIT target $ (547 ) (386 ) (10 ) (2 ) $ (149 ) $(100)-(75) $(75)-0

Transport Capacity and Demand Charges 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Alliance 5418656 5418656 5418656 5418656 5418656 5418656 5418656 5418656 5418656 5418656 5418656 Kern River 1542143 1532903 1532903 1537103 1532903 1532903 1532903 1537103 1511905 Third Party Transporter 2315627.77 944758.26 180270 EP Owned 3079672 2614487 1479202 1483255 1467502 908088 473047 474343 473047 473047 473047 385491 384438 284396 284396 285176 284396 284396 284396 285176 284396 252880 163271 83417 Volume/Day 1428584 757292 597292 589041 582541 537541 477541 477541 398882 398882 239286 239286 239286 239286 144286 144286 144286 144286 144286 144286 144286 100000 50000 Monthly Demand Charge (USD) Daily Volume (MMBtu) In 2004 EPM generated revenue of $39 MM on demand charges of $149 MM Alliance Kern River Third Party Transporter EP Owned Volume/Day

Legacy Sales Obligations 183,000-803,000 MMBtu/d Approximately 90% of obligations are priced based on an index Remaining fixed price obligations are hedged in our fixed price book Approximately 60% of our obligations are markets on El Paso pipelines

Summary Winding down non-Brazilian power business Focus on solving Brazil contract disputes Reduced MTM earnings volatility due to hedge designation and sale of CBI/II

Appendix

Disclosure of Non-GAAP Financial Measures The SEC's Regulation G applies to any public disclosure or release of material information that includes a non-GAAP financial measure. In the event of such a disclosure or release, Regulation G requires (i) the presentation of the most directly comparable financial measure calculated and presented in accordance with GAAP and (ii) a reconciliation of the differences between the non-GAAP financial measure presented and the most directly comparable financial measure calculated and presented in accordance with GAAP. The required presentations and reconciliations are provided herein. Additional detail regarding non-GAAP financial measures can be renewed in our full operating statistics posted at www.elpaso.com in the investors section. El Paso uses the non-GAAP financial measure "earnings before interest expense and income taxes" or "EBIT" to assess the operating results and effectiveness of the company and its business segments. The company defines EBIT as net income (loss) adjusted for (i) items that do not impact its income (loss) from continuing operations, such as extraordinary items, discontinued operations, and the impact of accounting changes; (ii) income taxes; (iii) interest and debt expense; and (iv) distributions on preferred interests of consolidated subsidiaries. The company excludes interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate the company's operating results without regard to its financing methods or capital structure. El Paso's business operations consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. As a result, the company believes that EBIT, which includes the results of both these consolidated and unconsolidated operations, is useful to its investors because it allows them to evaluate more effectively the performance of all of El Paso's businesses and investments. El Paso defines EBITDA as EBIT plus depreciation, depletion, and amortization. EBITDA is a measure that indicates a company's ability to service interest expense and capital expenditures. Operating Cash generated reflects cash generated by all operating activities of the firm and is intended to differentiate cash generated by operating activities from cash derived through changes in working capital and other sources. Free Cash Flow reflects operating cash after capital expenditures and payment of dividends and is indicative of cash that may be available for repayment of debt, acquisitions or new growth opportunities available to the firm. Per-unit cash expenses equal total operating expenses less DD&A and other non-cash charges divided by total production. It is a valuable measure of operating efficiency. El Paso believes that the non-GAAP financial measures described above are also useful to investors because these measurements are used by many companies in the industry as a measurement of operating and financial performance and are commonly employed by financial analysts and others to evaluate the operating and financial performance of the company and its business segments and to compare the operating and financial performance of the company and its business segments with the performance of other companies within the industry. These non-GAAP financial measures may not be comparable to similarly titled measurements used by other companies and should not be used as a substitute for net income, earnings per share or other GAAP operating measurements.

Forward-looking Non-GAAP Statement Certain Non-GAAP financial measures included herein are presented on a forward-looking basis. Regulation G requires that forward-looking Non-GAAP financial measures be reconciled to the appropriate forward-looking GAAP financial measure. In our budgeting process, we do not forecast certain financial statement line items, which are required to properly reconcile our forward-looking Non-GAAP financial measures. As a result, we have not included in this presentation any reconciliations of our forward-looking Non- GAAP financial measures. Please note that the unavailable reconciling items could significantly impact our net income and cash flows.

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Non-GAAP Reconciliation: Operating Cash Generation Net loss before discontinued operations DD&A Deferred income tax benefit Loss on long-lived assets Losses from unconsolidated affiliates, adjusted for cash distributions Other non-cash income items Operating cash generation $ (878 ) 1,088 (58 ) 1,092 (135 ) 445 $ 1,554 Twelve Months Ended December 31, 2004 $ Millions

Non-GAAP Reconciliation: Total Cash Expenses 2004 total equivalent volumes (MMcfe) Revenue Less: Transportation and net product costs Total operating margin Depreciation, depletion, and amortization Production costs Ceiling test and other charges General and administrative expenses Taxes other than production and income Operating income 2004 Per Unit Cash Cost Production cost General administrative expenses Total 297,766 $ 1,735 (54 ) $ 1,681 $ (548) (210 ) (22 ) (173 ) (2 ) $ 726 $ 5.83 (0.18 ) $ 5.65 $ (1.84 ) (0.71 ) (0.07 ) (0.58 ) (0.01 ) $ 2.44 $ 0.71 0.58 $ 1.29 Total ($ MM) Per Unit ($/Mcfe)

EPPH

1Q04 2Q04 3Q04 4Q04 Texas Gulf Coast 66 48 36 41 Onshore 209 207 222 221 Offshore 274 192 157 151 Production by Division: Daily Volumes 2004 average daily production 456 MMcfe/d 549 447 415 413 MMcfe/d Texas Gulf Coast Onshore Offshore 66 48 36 41 209 207 222 221 274 192 157 151

EPPH Reserve Reconciliation Beginning balance 12/31/20031 Production Sale of reserves in place Purchases of reserves in place Extensions and discoveries Revisions Ending balance 12/31/20042 1,541 (167 ) (25 ) 15 55 (132 ) 1,288 Equivalent (Bcfe)3 1HH = $6.03/MMBtu, WTI = $32.52/Bbl 2HH = $6.22/MMBtu, WTI = $43.45/Bbl, Brent = $40.47/BBl 3Approximately 94% of 12/31/2004 reserves are Natural Gas Note: Figures may not total due to rounding

PDP PDNP PUD 802 126 360 EPPH Year-end 2004 Reserves Base PDP PDNP PUD 1941 297 517 $2.8 Billion PV10% 1,288 Bcfe PDP $1,942 70% PUD $517 19% PDNP $297 11% PDP 802 Bcfe 62% PDNP 126 Bcfe 10% PUD 360 Bcfe 28% Very high proportion of reserves are proved developed

EPPH Domestic Regions Onshore Closed $179 MM East Texas acquisition in February 2005 1,084 Bcfe proved reserves 14.4 R/P ratio* $2.1 billion pre-tax PV-10% 137 Bcfe proved reserves 2.4 R/P ratio* $.5 billion pre-tax PV-10% GOM Texas Gulf Coast Closed $32 MM South Texas acquisition in January 2005 66 Bcfe proved reserves 5.0 R/P ratio* $.2 billion pre-tax PV-10% *Based on January 2005 production annualized

Q&A

Long-Range Plan Update March 17, 2005