2006 Analyst Meeting January 18, 2006

Cautionary Statement Regarding Forward-looking Statements The reserves and production information in this presentation, and the reserve replacement costs derived from this information include the proved gas and oil reserves and production attributable to El Paso's 43 percent interest in Four Star Oil & Gas Company ("Four Star"). El Paso's Supplemental Oil and Gas disclosures, which will be included in its Annual Report on Form 10-K, will reflect its proportionate share of the proved reserves of Four Star separately from its consolidated proved reserves. In addition, the proved reserves attributable to its proportionate share of Four Star represent estimates prepared by El Paso and not those of Four Star. 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 16, 2006; our ability to implement and achieve our objectives in the 2006 plan as set forth in this presentation, including achieving our debt-reduction targets, earnings and cash flow targets; changes in reserve estimates based upon internal and third party reserve analyses; the effects of any changes in accounting rules and guidance; 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. Cautionary Note to U.S. Investors - The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation, such as net risked reserves and gross unrisked reserves, that the SEC's guidelines strictly prohibit us from including in filings with the SEC. U.S. Investors are urged to consider closely the disclosures regarding proved reserves in this presentation and the disclosures contained in our Form 10-K for the year ended December 31, 2004, as amended, File No. 001-14365, available from by writing; Investor Relations, El Paso Corporation, 1001 Louisiana St., Houston, TX 77002. You can also obtain this form from the SEC by calling 1-800-SEC-0330. 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 EBIT, EBITDA, free cash flow, net debt and liquidity, and the required reconciliations under Regulation G, are set forth in the appendix hereto. 2

Schedule 8:30 a.m. Introduction Bruce Connery Vice President, Investor & Public Relations Doug Foshee President and Chief Executive Officer 8:55 a.m. Financial Review Mark Leland Executive Vice President and Chief Financial Officer 9:15 a.m. Exploration & Production Overview Lisa Stewart President, Exploration & Production and Non-Regulated Operations 9:45 a.m. Review of Marketing & Trading Bryan Neskora Vice President, Marketing & Trading 9:55 a.m. Regulated Overview and Macro Outlook Jim Yardley President, Southern Natural Gas 10:10 a.m. Summary 10:15 a.m. Q&A Estimated Time (EST) 3

Schedule 10:45 a.m. Break 11:00 a.m. Review of Pipeline Regions Steve Beasley, President, Eastern Pipelines Jim Cleary, President, Western Pipelines Jim Yardley, President, Southern Natural Gas 11:50 p.m. Q&A 12:00 p.m. Lunch (no presentation) 1:00 p.m. Review of Power Business Lisa Stewart 1:15 p.m. Review of Exploration & Production Regions Antonio de Pinho, Vice President, International Al Erxleben, Vice President, Gulf of Mexico Jim Bass, Sr. Vice President, Texas Gulf Coast Bill Griffin, Sr. Vice President, Onshore Operations 2:45 p.m. Q&A 4 Estimated Time (EST)

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

the place to work the neighbor to have the company to own

What We Said About 2006 in 2003 EPS: $0.75-$1.10 EBITDA: $3.2 billion-$3.6 billion Capex: $1.6 billion-$1.7 billion Net debt: $14.5 billion-$15.5 billion Strong North American natural gas company Pipelines: U.S. and Mexico Exploration & Production: U.S. and Brazil Marketing and Physical Trading Two-year turnaround

What We Say About 2006 Now EPS: $0.95-$1.05 EBITDA: $3.4 billion-$3.6 billion Capex: $2 billion Net debt: $14 billion Strong North American natural gas company Pipelines: U.S. and Mexico E&P: U.S. and Brazil Marketing and Physical Trading Still some legacy issues We will meet our commitments

What Happened In-Between Much higher commodity prices E&P much more challenging than projected Asset sales much better than expected East Texas and Medicine Bow acquisitions More pipeline infrastructure Katrina and Rita Some legacy issues more challenging Power restructuring - Margin calls Tolling - Government investigations Henry Hub and hard work offset E&P issues

Significant Progress Since December 2003 $5.8 billion of assets sold or pending Reduced net debt by $3.4 billion* Eliminated liquidity concerns Exited petroleum and midstream businesses Sold most domestic and international power assets Substantially downsized trading book *As of September 30, 2005

Significant Progress Since December 2003 Reduced corporate expenses Simplified organizational structure Completely new management team Implemented industry-leading reserve reporting process Communicated progress/shortfalls towards goals Further strengthened Board of Directors Demonstrated leadership in corporate governance

Where We Are Today-Pipelines Best overall pipeline franchise in North America Size - Growth opportunities Diversity - Management Storage Biggest backlog in history Rockies supply - Major market areas LNG - Storage Growth capital generates solid value Low risk Balance Incredible franchise

Where We Are Today-E&P Portfolio rebalanced-50% increase in R/P Capex created value in 2005 and will again in 2006 New team and culture Deep inventory of opportunity Always room for improvement 2005 year end reserves: 2.7 Tcfe*, up 22% All-in F&D $2.36/Mcfe 94% of production replaced with drill bit 275% production replacement *Includes 43% interest in Four Star

Where We Are Today-Legacy Issues Litigation Government investigations Domestic power Central American power Brazil power Trading book Transportation capacity There is a plan to manage each issue

Pipeline Outlook North America infrastructure requirements are tremendous El Paso will continue industry leadership Strong market presence with unmatched connectivity $450 MM-$550 MM of annual growth capital 2006 and beyond Continued success in recontracting 4%-6% EBITDA growth annually

E&P 2006 Outlook EBITDA up 20%+ year-to-year Total production up 8%-11% year-to-year Reserve growth 5%-10% year-to-year Production will incline through year Reserve life should continue to grow E&P will break out in 2006

2006 Financial Targets EPS of $0.95-$1.05 Does not include MTM impact from production-related derivatives EBITDA: $3.4 billion-$3.6 billion Capex: $2 billion $1,275 MM maintenance capital $770 MM growth capital +-$400 MM free cash flow after significant growth capital Note: Assumes $8/MMBtu natural gas and $60/Bbl WTI

Financial Review

Fourth Quarter 2005 Simplification Closed several major transactions Midstream sale $ 642 Power book sale* $ 442 Cordova tolling transfer $ (177 ) Chinese power plants $ 70 Intercontinental Exchange $ 42 Other $ 22 Other clean up $ Millions *Total realized after final contract assignments

Solid Momentum As We Enter 2006 Debt exchange for El Paso CGP Company bonds Elimination of El Paso CGP registrant All domestic E&P properties moved to El Paso Exploration & Production Company (formerly EPPH) Contracted Central America power plant sale: $141 MM* *Excludes Dominican Republic and Peru assets

Primary 2006 Financial Objectives Grow core businesses Generate free cash flow Further reduce debt Improve credit metrics

Economic Assumptions for 2006 Results $8.00/MMBtu Henry Hub 95% realization before hedges $60/Bbl WTI 97% realization before hedges $500 MM equity offering during 2006

Accounting Rule Changes for 2006 Option expense $(16 ) Pipeline integrity costs (FERC) (26 ) Total $(42 ) $ Millions

2006 Gas Hedge Summary Designated Gas Hedges Fixed price swap Economic Gas Hedges Fixed price swap Ceiling Floor 85 25 60 120 $ 6.34 1 $ 8.11 $ 9.50 $ 7.00 $ 3.96 2 $ 8.11 3 $ 9.50 3 $ 7.00 3 Notional Volume (Bcf) Avg. Hedge Price Avg. Cash Price 1Earnings impact realized through E&P segment on accrual basis 2Dollar for dollar margin requirements and monthly cash settlements impact working capital in Marketing segment 3Earnings recognized through mark-to-market accounting in Marketing segment

2006 Capital Program Maintenance1 Growth Total $ 575 470 $ 1,045 $ 700 2 300 $ 1,000 $ 1,275 770 $ 2,045 Pipelines Exploration & Production Total $ Millions Significant growth capital in core businesses 1Includes an estimated $100 MM of hurricane-related capex not recoverable from insurance 2Capital assumed to replace production

2006 Key Metrics Pipeline EBIT Exploration & Production EBIT Volumes (MMcfe/d) DD&A rate ($/Mcfe) Cash costs ($/Mcfe) Marketing & Trading EBIT2 $1,380 MM-$1,420 MM $1,000 MM-$1,050 MM 825-8501 $2.00-$2.15 $1.64-$1.71 $(80) MM +- 1Assumes 8 MMcfe/d deferred due to hurricane-related issues; reversion of 30 MMcfe/d of Brazilian production in January 2Excluding mark-to-market impact on hedges and remaining trading activity

Core Earnings Buildup Pipelines Exploration & Production Marketing & Trading and other Non-Regulated Corporate and other Total $1,380-$1,420 1,000-1,050 (55)-(35) 25 $2,350-$2,460 EBIT DD&A EBITDA 2006 $ 470 610 5 15 $ 1,100 $1,850-$1,890 1,610-1,660 (50)-(30) 40 $3,450-$3,560 $ Millions

2006 Core Earnings and Cash Flow* EBITDA DD&A EBIT Interest Taxes at 38% Net income Non-cash adjustments DD&A Non-cash taxes (90%) Working capital changes & other Operating cash Dividends Maintenance capital Discretionary cash Growth capital Free cash 28 $3,450-$3,560 1,100 $2,350-$2,460 1,275 408-450 $667-$735 $1,100 368-405 400+- $2,535-$2,640 $110 1,275 1,150-1,255 770 $380-$485 $0.95-$1.05 $3.62-$3.77 EPS Cash Per Share $ Millions, Except Earnings & Cash Per Share *Excludes MTM impact on hedges

Corporate Cost Summary 2005E 2006 Plan Corporate Cost 525 300 Insurance and benefits Greenway lease expense Litigation settlements and reserves Smaller corporate center $ Millions $525 $300* *Total corporate costs before allocation to business units. Includes $35 MM litigation expenses allocated to business units in 2006 but not in 2005

Debt Progression Outstanding net debt at 9/30/05 Estimated net debt at 12/31/05 Sources Free cash flow Equity offering Asset sales and other Target net debt at 12/31/06 $ 17.0 16.1 0.4 0.5 1.2 $ 14.0 $ Billions

Stronger Capital Structure Debt Securities of subsidiaries Preferred stock Stockholders equity Book capitalization Debt to capital Weighted cost of debt Net debt to EBITDA* EBITDA to fixed charges* Sep. 30, 2005 $ 17,924 59 750 2,692 $ 21,425 83.7 % 7.9 % 13.23 x 0.83 x Dec. 31, 2006E $ 15,240 59 750 4,200 $ 20,240 75.3 % 8.0 % 3.99 x 2.44 x $ Millions *Based on last twelve months

Maturity Schedule at December 31, 2005 Capital market debt-Non-pipeline Pipeline capital market debt B-Loan Bank debt Other* Total maturities El Paso Zero Coupon Convert (Put) Total including Zero Coupon Convert Other discretionary debt repayments $ 341 - 20 12 113 $ 486 615 $ 1,101 $2,000 2006E $ Millions *Excludes $115 MM of Macae debt that matures beyond 2006 December 31, 2005 liquidity $2.3 billion

Sensitivity Analysis1 EBITDA2 Earnings per share Free cash flow $ Millions, Except Earnings Per Share $ 69 $ 0.10 $ 69 $1.00 Change in Gas Prices $1.00 Change in Oil Prices 20 MMcf/d at $8.00 Production Free cash flow positive down to $5.50/MMBtu + ^ $ (61 ) $ (0.09 ) $ (61 ) + ^ $ 4 $ 0.01 $ 4 $ (4 ) $ (0.01 ) $ (4 ) $ 42 $ 0.06 $ 42 + ^ $ (42 ) $ (0.06 ) $ (42 ) 1Full year 2006 2Includes change in Four Star distributions; excludes MTM changes

Exploration & Production Overview

Restructuring Complete New management Capital discipline instilled in organization Portfolio much better balanced: Risk and reserve life Multi-year inventory delivers solid returns at plan prices All regions will create value in 2006 and beyond

2005 Summary Onshore Production of 324 MMcfe/d* 29% organic production growth Reserves growth of 43% to 1,710 Bcfe* 99% drilling success rate of 453 of 454 wells Significant acquisition activity added 494 Bcfe Generated PVR of 1.23 Texas Gulf Coast Production of 211 MMcfe/d YE reserves of 468 Bcfe 89% drilling success rate (16 of 18 wells); 100% in 2H Generated PVR of 1.02, 1.65 in 2H GOM/SLA Average 179 MMcfe/d (213 MMcfe/d w/o hurricanes) YE reserves of 240 Bcfe 73% drilling success rate (8 of 11 wells) Generated PVR of 1.19 Brazil Production of 53 MMcfe/d Reserves of 250 Bcfe Rio de Janeiro *Includes our 43.1% share of Four Star 36

Reserve Reconciliation Beginning balance 12/31/2004 Production Sale of reserves in place Purchases of reserves in place Extensions and discoveries Revisions Ending balance 12/31/2005 2,181 (280 ) (25 ) 529 242 21 2,668 Equivalent (Bcfe) Note: Includes our 43.1% share of Four Star (see Appendix) 22% Growth

Onshore TGC GOM International 1711 468 240 250 YE 2005 Reserves Base Total Reserves 2,668 Bcfe $9.2 Billion PV10% Onshore 1,710 Bcfe 64% TGC 468 Bcfe 18% GOM 240 Bcfe 9% Note: Includes our 43.1% share of Four Star International 250 Bcfe 9% PDP PDNP PUD 1262 285 634 PDP 1,579 Bcfe 59% PDNP 306 Bcfe 12% PUD 783 Bcfe 29%

2005 Quarterly Production Note: Includes our 43.1% share of Four Star MMcfe/d 1Q2005 2Q2005 3Q2005 4Q2005E GOM 232 218 161 107 TGC 228 222 199 196 Onshore 247 294 348 405 International 59 50 51 51 Hurricane Impact 39 97 766 784 798 856 97 39 Average Production: 767 MMcfe/d

Hurricane Update Current GOM production: 130 MMcfe/d 2005 production losses: 12 Bcfe Significant projects: WC 62/75 sales: February 2006 (23 MMcfe/d) EI 372 3rd party repairs: February 2006 (20 MMcfe/d) Most operated production restored by 2Q 2006 3rd party restoration: 10 MMcfe/d (timing unknown)

Acquisition Success Completed $1.1 billion of acquisitions at $2.17/Mcfe East Texas and South Texas deals more tactical, augmenting existing core areas Medicine Bow transaction strategic Extended reserve life Significantly expanded Rockies presence Key elements of Medicine Bow assets Operated assets contain multiple opportunities Four Star Oil & Gas Company (43% interest) Very stable, long-lived production Significant free cash flow Many opportunities for "block and tackle" enhancements in San Juan and Hugoton basins

Acquisition Discipline Note: EP's acquisition metrics reflect zero goodwill and purchase price allocations of approximately 80% to proved reserves Source: JS Herold's 2005 transactions through 11/30/2005; Mean, Median of 63 companies Weighted Average $//Mcfe Good value in current commodity price environment

Stabilizing Reserve Profile 6.1 7.2 9.5/9.12 R/P Ratio: 1Includes our 43.1% share of Four Star 2Actual/hurricane adjusted 2003 2004 2005 2006E East 2520 2184 2668 2668 Year-end reserves: 2,520 Bcfe Year-end reserves: 2,184 Bcfe Year-end reserves: 2,668 Bcfe 2003 2004 2005 2006E East 410 107 137 105 303 273 305 Full-year production: 410 Bcfe Full-year production: 303 Bcfe Full-year production: 280/292 Bcfe2 9.8-9.0 Assuming 5-10% reserve growth: 2,800-2,950 Bcfe Plan production: 300-310 Bcfe 1 1

Improved Production Mix MMcfe/d 1/1/2004 2/1/2004 3/1/2004 4/1/2004 5/1/2004 6/1/2004 7/1/2004 8/1/2004 9/1/2004 10/1/2004 11/1/2004 12/1/2004 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 1/06E 2/06E 3/06E 4/06E 5/06E 6/06E 7/06E 8/06E 9/06E 10/06E 11/06E 12/06E International Less Disc 905 905 892 836 808 768 751 812 765 761 773 790 748 753 797 772 803 777 764 744 769 733 786 777 743 754 793 814 814 816 836 851 881 897 936 950 TGC 905 905 892 836 808 768 751 753 710 703 719 729 690 692 739 730 747 725 712 692 719 677 735 718 717 729 767 787 787 791 811 826 856 872 911 927 GOM 591 595 592 515 502 475 487 487 454 450 471 471 466 461 510 503 517 517 508 498 519 470 543 536 542 559 598 613 615 613 621 638 658 671 699 715 Onshore 215 222 235 218 223 228 228 243 245 235 244 236 220 235 286 282 292 309 319 315 411 406 415 406 407 409 412 415 421 426 433 442 447 455 461 468 TGC GOM Onshore (includes Four Star) International Katrina Expected 2005 to 2006 average volume growth of 8% to 11%

Plan Metrics Production (MMcfe/d)1 Capital expenditures ($ MM) E&D Acquisitions Realized prices (includes hedges)2 Gas ($/Mcf) Liquids ($/Bbl) Production costs ($/Mcfe)3 Other taxes ($/Mcfe) General and administrative expenses ($/Mcfe) Total cash expenses4 2006 Plan 825-850 $ 1,000 - $ 6.96 $52.12 $ 1.02-$1.05 0.04-0.05 0.58-0.61 $1.64-$1.71 1Includes our 43.1% share of Four Star 2Prices are stated after transportation costs 3Production costs include lease operating expenses plus production related taxes 4Cash expenses equal total operating expenses less DD&A and other non-cash charges 2005E 767 $ 718 1,149 $ 6.20 $44.96 $ 0.96 0.04 0.67 $ 1.67

Managing Inflation Efficiency improvements Aligned with service providers to leverage $1 billion capital program Ability to meet projected activity levels Longer term rig contracts in key areas

Remain Focused on the Basics Spent $109 MM in production enhancements Cycle time improvements resulted in more production days Implemented new field efficiency program: EP PRIDE

Average Rig Activity 1Q 2005 2Q 2005 3Q 2005 4Q 2005 2006E Drilling and Completion 23 22 20 19 29 Recompletions 5 7 5 2 6 Workovers 7 5 4 4 3 Total drilling and completion Total recompletions Total workovers 35 34 29 38 25

Healthy Drilling Inventory Inventory generates 1.15 PVR at $5.50 price deck Conventional Gas Onshore Division Texas Gulf Coast Non-Conventional Gas Onshore Oil Gulf of Mexico/South Louisiana Total Domestic International Total Company 133 43 353 62 29 620 9 629 2006 Plan Future Years Total 490 80 1,630 290 100 2,590 30 2,620 4 3 5 6 4 5 4 5 Number of Wells

Onshore Significant Acreage Developed Gross: 753,000 Net: 523,000 Undeveloped Gross: 1,400,000 Net: 1,185,000 More than 3 million gross acres in high-quality basins Developed Gross: 530,000 Net: 363,000 Undeveloped Gross: 541,000 Net: 495,000 GOM/SLA TGC Developed Gross: 105,000 Net: 79,000 Undeveloped Gross: 153,000 Net: 108,000 Note: Excludes FSOG acreage 50

2006 E&P Capital Allocation Onshore continues proven development program Texas Gulf Coast builds on 2H05 development success with exploration exposure GOM provides short-life, high-return investment opportunities with significant exploration exposure International builds for the future Total = $1,000 MM Texas Gulf Coast GOM/S. Lousiana Onshore International East 182 243 488 87 Texas Gulf Coast $180 MM Int'l $90 MM Onshore $490 MM GOM $240 MM

Balanced Drilling Portfolio High (Pc < 40%) Med Low (Pc > 80%) % of 2006 Drilling Capital Risked Reserve Exposure (Bcfe) GOM Expl. Int'l Expl. GOM Dev. Ons. Expl. Onshore Dev. TGC Dev. 12% 46 20% 73 68% 342 Risk TGC Expl. Int'l Dev. 16 60 553 Gross Wells

2005 Drilling Results 2005 Plan Pre-Drill PVR on Corporate Plan Deck1 Post-Drill PVR on Corporate Plan Deck1 Post-Drill PVR on Strip Prices2 Onshore SLA/GOM TGC 1.24 1.33 1.07 Onshore SLA/GOM TGC 1.23 1.19 1.02 Ons. GOM/SLA TGC Predicted Success Total PVR = 1.23 Total PVR = 1.19 Total PVR = 2.11 Ons. GOM/SLA TGC Ons. GOM/SLA TGC 99% 73% 89% Onshore SLA/GOM TGC 2.14 2.38 1.57 12005 Plan price of $4.75/MMBtu 2NYMEX strip at 12/30/05 99% 67% 83% Actual Success 53

2006 Drilling Onshore SLA/GOM TGC 1.26 1.51 1.29 Onshore SLA/GOM TGC 1.78 2.06 1.73 Ons. GOM/SLA TGC Total PVR = 1.33 Total PVR = 1.84 Total PVR = 2.24 Ons. GOM/SLA TGC Ons. GOM/SLA TGC Onshore SLA/GOM TGC 2.15 2.52 2.09 PVR on $5.50 Deck PVR on $8.00 Deck PVR on Strip Deck* Predicted Success 98% 62% 83% *NYMEX strip at 12/30/05 54

Maintenance Burden Declining Lower Risk = Higher Value Source: Peers are 2006 estimates by JPM Equity Research, October 4, 2005; see Appendix for EP base assumptions Ratio of Maintenance Capex to Discretionary Cash Flow

Portfolio of Opportunity Each region has a balanced inventory 2006: Solid program Beyond: Significant inventory Capital allocation decisions to meet key objectives Deliver predictable baseline results Continue shift to less risky production profile Retain exposure to high impact projects Result: Predictability plus growth

Review of Marketing & Trading

Transition of Marketing Business Cordova transaction Power book transactions Economic hedge roll-off Dec. 31, 2002 Dec. 31, 2006 Transactions 36882 1100 Transaction Count 36,882 <1,100 Reduced earnings volatility

Mark-to-Market Trade Book by Commodity Gas Power Cordova Economic hedges Low Medium High High Book slightly long length offsets fuel requirements in transportation portfolio Remaining commodity exposure hedged at PJM west hub; open PJM basis position Sold to Constellation December 2005 Majority rolls off in 2006 $ (15 ) $ (500 ) $ - $ (235 ) Volatility Status Approx. Value at 12/31/05 ($ MM) Exposure to commodity price movements greatly reduced in 2005

El Paso Power Exposure in PJM Delivery obligation equals 33 MMWh through 2016 100% of the energy hedged at the PJM west hub through 2016 Locational basis differential and capacity between PJM west hub and delivery points remains unhedged Historical locational basis showed little volatility before December 2004 Rising gas prices and transmission congestion caused locational basis settlements to double during 2005 PJM West PJM East Delivery obligations from west to east provides basis exposure

Legacy Gas Supply Obligations Up to 1 Bcf/d Approximately 90% of obligations are index priced Remaining fixed price obligations are hedged Approximately 55% of our obligations are markets on El Paso pipelines In 2005, $120 MM of net revenues on $156 MM of demand charges Low earnings volatility due to index-based portfolio

Transport Capacity and Demand Charges 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Alliance 66.6 67 67.3 67.7 67.9 68 68.3 68.5 68.7 63 0 0 0 0 0 0 0 0 0 0 0 0 0 Kern 18.4 18.4 18.5 18.4 18.4 18.4 18.5 6.1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 EP Owned 36.9 34.7 34.6 34.5 28.5 23.4 22.2 20.8 20.8 20.8 19.7 18.5 18.5 16 15.2 15.1 15.1 15.1 15.2 15.1 14.6 8.5 6.8 Third Party 11.5 3.2 2.8 2.8 2.8 1 0.9 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total 1.2 0.7 0.7 0.7 0.7 0.6 0.6 0.4 0.3 0.3 0.2 0.2 0.2 0.2 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.05 0.05 Alliance Kern EP Owned Third Party Annual Demand Charge ($ MM)

Summary Significant progress in eliminating commodity risk in 2005 Complete exit of power trading as market permits Legacy gas book complimentary to production business Focusing efforts on maximizing the value of E&P company's gas and oil

Regulated Overview and Macro Outlook

EP Pipeline Group: One of a Kind Largest natural gas infrastructure franchise Market presence and scope offer true competitive advantage Fundamentals in place for industry leading growth Paves way for large-scale projects Elba Expansions and Elba Express Continental Connector Minimum $450 MM+ annual growth capital

Leading Natural Gas Pipelines 66 Tennessee Gas Pipeline Elba Island LNG Florida Gas Transmission (50%) Southern Natural Gas ANR Pipeline Great Lakes Gas Transmission (50%) Colorado Interstate Gas Wyoming Interstate El Paso Natural Gas Mojave Pipeline Mexico Ventures Cheyenne Plains Pipeline 26% total U.S. interstate pipeline mileage 36 Bcf/d capacity (25% of total U.S.) Best market connectivity Best supply access Leading pipeline integrity program

Leading Storage and LNG Player 36 Bcf 233 Bcf 48 Bcf 96 Bcf Elba Island LNG 7 Bcf 413 Bcf storage/ 9.1 Bcfd withdrawal capacity 11% of US underground storage 1 of 4 existing onshore LNG terminals in U.S. 26% of U.S. terminal storage capacity Working Gas Capacity

Big Picture Natural gas demand will increase approximately 2% per annum 2006-2015 Driven by power generation demand LNG, Rockies supplies integral to meeting demand Significant infrastructure development required

GOM WCSB "Production Alley" Continues to be Axis of Supply Eastern Markets 2004-2014 + 10 Western Markets 2004-2014 + 4 Production Alley (Greater than 82% Supply) Demand Change in Bcf/d LNG

0.6 0.3 0.6 1.3 MacKenzie Delta 0.5 7.2 0.9 0.9 0.1 N.A. LNG Imports 13.4 0.8 0.7 2.1 0.4 0.8 1.4 0.8 0.7 0.9 0.8 0.4 0.4 0.8 3.2 0.6 Major Changes in Gas Flows 2004-2014 (Bcf/d)

Unprecedented Growth ANR Wisconsin 2006 $47 MM November 2006 168 MMcf/d TGP NE ConneXion New England $108 MM 2007/08 136 MMcf/d TGP NE ConneXion NY/NJ $27 MM November 2006 42 MMcf/d TGP Essex- Middlesex $38 MM November 2007 82 MMcf/d TGP LA Deepwater Link $28 MM October 2006 850 MMcf/d TGP/ANR Eugene Island 371 $16 MM June 2006 200 MMcf/d FERC Certificated/ Under Construction Signed PA's Future Projects ANR STEP $81 MM 2007/08 26 Bcf / 400 MMcf/d EPNG Line 1903 $74 MM December 2005 502 MMcf/d WIC Piceance Pipeline $132MM March 2006 333 MMcf/d WIC Kanda Lateral Up to $137MM January 2008 Up to 333 MMcf/d SNG Cypress Phase I $241MM May 2007 220 MMcf/d SNG Elba Expansion II $158MM February 2006 360 MMcf/d ANR Wisconsin 2007 $45 MM November 2007 100 MMcf/d Mexico JV- LPG Reynosa $53 MM (50%) July 2007 30,000 Bbl/d Mexico JV - Sonora $390 MM (33%) 2009 1000-1250 MMcf/d EPNG Sonora Lateral $91MM 2009/10 800 MMcf/d Continental Connector $1+Billion 2007/08 1+ Bcf/d Cheyenne Plains $385MM December 2005 755 MMcf/d CPG Yuma Lateral $22 MM October 2006 49 MMcf/d FGT Phase VII $63MM May 2007 100 MMcf/d SNG Elba Expansion III & Elba Express $850MM 2010 - 2012 8.4 Bcf / 900 MMcfd CIG Raton Basin Expansions $91MM 2005-2008 170 MMcf/d EPNG Arizona Storage $105MM 2009/10 350 MMcf/d

Growth is diverse 72 ANR Wisconsin 2006 $47 MM November 2006 168 MMcf/d TGP NE ConneXion New England $108 MM 2007/08 136 MMcf/d TGP NE ConneXion NY/NJ $27 MM November 2006 42 MMcf/d TGP Essex- Middlesex $38 MM November 2007 82 MMcf/d TGP LA Deepwater Link $28 MM October 2006 850 MMcf/d TGP/ANR Eugene Island 371 $16 MM June 2006 200 MMcf/d Pipeline Storage LNG and related ANR STEP $81 MM 2007/08 26 Bcf / 400 MMcf/d EPNG Line 1903 $74 MM December 2005 502 MMcf/d WIC Piceance Pipeline $132MM March 2006 333 MMcf/d WIC Kanda Lateral Up to $137MM January 2008 Up to 333 MMcf/d SNG Cypress Phase I $241MM May 2007 220 MMcf/d SNG Elba Expansion II $158MM February 2006 360 MMcf/d ANR Wisconsin 2007 $45 MM November 2007 100 MMcf/d Mexico JV- LPG Reynosa $53 MM (50%) July 2007 30,000 Bbl/d Mexico JV - Sonora $390 MM (33%) 2009 1000-1250 MMcf/d EPNG Sonora Lateral $91MM 2009/10 800 MMcf/d Continental Connector $1+Billion 2007/08 1+ Bcf/d Cheyenne Plains $385MM December 2005 755 MMcf/d CPG Yuma Lateral $22 MM October 2006 49 MMcf/d SNG FGT Phase VII $63MM May 2007 100 MMcf/d SNG Elba Expansion III & Elba Express $850MM 2010 - 2012 8.4 Bcf/ 900 MMcfd CIG Raton Basin Expansions $91MM 2005-2008 170 MMcf/d EPNG Arizona Storage $105MM 2009/10 350 MMcf/d

2006 Focus Operate safely and dependably Restore facilities and business from hurricanes Favorably resolve EPNG rate case Successfully contract open capacity Continue cost control and efficiency improvements Manage costs/timing of "committed" growth projects Secure commitments for new growth projects

Summary 2006 a breakout year for EP Pipelines pursuing significant opportunities Exploration & Production will deliver solid results Credit metrics will improve sharply EP will solidify position as premier North American natural gas company

Q&A

Review of Pipeline Regions

Eastern Pipelines

Eastern Pipeline Group Overview Strategic Initiatives Project Development New Business Platforms Summary

Eastern Pipelines Great Lakes Gas Transmission (50%) 2,100 miles 3 Bcf/d Transmission ANR Pipeline 10,500 miles 7 Bcf/d Transmission 233 Bcf Storage Tennessee Gas Pipeline 14,200 miles 7 Bcf/d Transmission 90 Bcf Storage Mexico Ventures (50%) 106 miles 2 Bcf/d Transmission

Eastern Pipelines Longline pipelines Multiple regions Highly differentiated markets Diverse customer base In the path of growth New supply opportunities Continuing growth and market franchises Competitive corridors: Challenges and opportunities

Strategic Initiatives Optimizing contract portfolio Market segmentation/differentiation Efficiency initiatives Building value on both ends of pipe New business opportunities (Continental Connector project, LNG, storage)

Contract Expiration Portfolio As of December 2005 TGP ANR 2006 2007 2008 2009 2010 Beyond TGP 972 1177 920 868 847 2736 ANR 1259 1275 1083 1162 1253 1594 TGP & ANR Capacity 15,100 2,231 2,452 2,003 2,029 2,100 4,329 Thousands of Dth/d

Market Segmentation/Differentiation Franchise Market (mostly sold out) Battleground Market "Upgrade" Market

Building Value on Both Ends TGP NE ConneXion NY/NJ $27 MM November 2006 42 MMcf/d TGP Essex- Middlesex $38 MM November 2007 82 MMcf/d TGP LA Deepwater Link $28 MM October 2006 850 MMcf/d TGP/ANR Eugene Island 371 $16 MM June 2006 200 MMcf/d FERC Certificated/ under Construction Signed PA's Future Projects ANR Wisconsin 2007 $45 MM November 2007 100 MMcf/d ANR STEP $81 MM 2007/08 26 Bcf / 400 MMcf/d Mexico JV- LPG Reynosa $53 MM (50%) July 2007 30,000 Bbl/d Mexico JV - Sonora $390 MM (33%) 2009 1000-1250 MMcf/d Continental Connector $1+ Billion 2007/08 1+ Bcf/d TGP NE ConneXion New England $108 MM 2007/08 136 MMcf/d ANR Wisconsin 2006 $47 MM November 2006 168 MMcf/d

New Business Platforms: Continental Connector Tennessee Gas Pipeline Southern Natural Gas ANR Pipeline Colorado Interstate Gas Wyoming Interstate Cheyenne Plains Pipeline El Paso Natural Gas Florida Gas Transmission 25+ Bcf/d of Market Integration Capacity: 1+ Bcf/d Capex: $1+ Billion In-service: Winter 07/08

Sonora LNG: Strategic Opportunity EPNG EPNG EPNG EPNG San Juan Basin Permian Basin Anadarko Basin Mojave Kern River Sonora Pacific LNG Cd. Obregon Navojoa EPNG Phoenix Tucson Guaymas Capacity: 1.0 Bcf/d Terminal 7.0 Bcf Storage Capex: $1.2 Billion (Gross) Ownership: El Paso (1/3) In-service: 2009

Summary: Eastern Pipelines Optimizing the base Expanding with the markets Adding new supply-driven platforms

Western Pipelines

Western Pipelines Mojave Pipeline 400 miles 0.4 Bcf/d Transmission El Paso Natural Gas 10,900 miles 6 Bcf/d Transmission Colorado Interstate Gas 4,000 miles 3 Bcf/d Transmission 29 Bcf Storage Wyoming Interstate 600 miles 2 Bcf/d Transmission Cheyenne Plains Pipeline 400 miles 0.8 Bcf/d Transmission

Western Pipelines Serve diverse markets Multiple regions Distribution or gathering - like systems in key markets Significant growth opportunities Competitive markets: Challenges and opportunities

High Connectivity with Supply and Markets Supply Distribution 147 Colorado Delivery Points Bighorn Basin Powder River Basin Wind River Basin Red Desert Basin DJ Basin Piceance Basin Uinta Basin 84 Supply Receipt Points Watkins Air Injection Young Storage Ft. Morgan Storage Latigo Storage Flank Storage Boehm Storage 44 PSCo 6 CSU 14 Aquila 83 Other Green River Basin PSCo

Strategic Business Plan Favorably resolve rate cases EPNG January 2006 CIG October 2006 Successfully re-contract Develop storage to serve EPNG market area Focus on cost efficiencies, especially fuel use Successfully complete expansion projects Attach/transport new supply and new markets

Contract Expiration Portfolio Thousands of Dth/d 2006 2007 2008 2009 2010 Beyond EPNG/Mojave 1595 1384 483 218 539 2022 CIG/WIC/CP 424 1876 376 179 371 3419 EPNG/Mojave CIG/WIC/CP 93 As of December 2005 EPNG/Mojave & CIG/WIC/CP Capacity 11,900 2,019 3,260 859 397 910 5,441

Successful Recent Recontractings EPNG: SoCal Gas: 756 Mdth/d extended to 2009-2011 Southwest Gas (AZ) 476 Mdth/d: Contract continues under primary term until 2011 PG&E: 200 Mdth/d expires 2007-2010 Conoco: 190 Mdth/d expires 2008 Mojave Pipeline: Extended 312 Mdth/d for a 10-year term 55% of EPNG 2006 capacity and 78% of Mojave 2007 capacity

Over $1 Billion on Growth Projects 95 Cheyenne Plains $385 MM December 2005 755 MMcf/d FERC Certificated/ under construction Signed PA's Future Projects EPNG Sonora Lateral $91 MM 2009/10 800 MMcf/d EPNG Line 1903 $74 MM December 2005 502 MMcf/d WIC Piceance Pipeline $132 MM March 2006 333 MMcf/d WIC Kanda Lateral Up to $137 MM January 2008 Up to 333 MMcf/d CPG Yuma Lateral $22 MM October 2006 49 MMcf/d CIG Raton Basin Expansions $91 MM 2005-2008 170 MMcf/d EPNG Arizona Storage $105 MM 2009/10 350 MMcf/d

Summary: Western Pipelines Successful recontractings Progress in rate cases Capitalizing on significant supply and market growth opportunities

Southern Pipelines

Southern Pipelines Elba Island LNG 7 Bcf Storage Southern Natural Gas 8,000 miles 3 Bcf/d Transmission 60 Bcf Storage Florida Gas Transmission (50%) 4,800 miles 2 Bcf/d Transmission

Southern Pipelines: SNG and FGT Strong market position Concentrated customer base Distribution-like systems Competitive advantage Recent rate case settlements Fully subscribed Significant growth opportunities

Major Customers (% 2005 Revenue)* AGCL SCANA Alagasco So Co Other 2005 0.31 0.12 0.09 0.08 0.4 FPC TECO Progress Other 2005 0.41 0.165 0.047 0.378 Other AGLC SCANA Alagasco Southern Co. Other FPL Tampa Electric/Peoples Progress *FGT revenue from Oct '04 to Sept '05 SNG FGT

High-valued Service c 96 SNG physical delivery locations to Alagasco LEGEND Southern Natural Gas AGLC Transmission Lines Alagasco Transmission Lines AGLC Service Area SNG Delivery Points/ "Areas" Alagasco Service Area 52 SNG physical delivery locations to AGLC

SNG Rate Case Settlement-3Q 2005 Rate certainty through March 2009 Contract extensions through August 2010 Higher rate on contracts not extended Reduced fuel retention rates, with 50/50 sharing Maintenance capital surcharge

2006 2007 2008 2009 2010 2011 Beyond SNG 187 161.594691 69.367761 186.3325 1513.180197 105.127265 1395.007549 FGT 20.417 65.122 42 8.522 511.263 19.271 1640.917 Contract Expiration Portfolio Thousands of Dth/d SNG FGT FGT Capacity 2,200 SNG Capacity 3,400 As of December 2005

Significant Growth in the Southeast Elba Phase II nearly complete Cypress and FGT Phase VII Construction 2006-07 Elba Phase III and Elba Express FERC filing 3Q '06 More than $1.3 billion of growth projects

Elba's Customers & Capabilities Start-up Contract Term Dec-2001 22 yrs Feb 2006 30 yrs - - Reactivation Phase II Total Storage Capacity (Bcf) Sendout (MMcfd) Capex ($MM) 4.0 675 - 3.3 540 $155 15.7 2,115 $505 Phase III 2010/2012 long-term 8.4 900 $350

Elba Expansion Projects Phase II Slip Proposed Phase III Tanks Phase II Tank

SNG's Cypress Project Will Improve Supply to Southern GA and FL JEA Progress FL Cypress Project (Phase I) 165 miles 24" pipe Capacity: 220 MMcf/d Capex: $241 MM Pipe ordered FERC certificate expected 2Q '06 In-service May 2007 Supported by 20-year Agreements with BG & Progress FGT Phase VII Capacity: 100 MMcf/d Capex: $63 MM In-service May 2007 Elba Island

Elba Express Pipeline Will Improve Supply to Georgia and the East Coast Transco Elba Express Pipeline Pipe: 42"/36"; 191 miles Capacity: 1,175 MMcf/d Capex: $510 MM In-service: 2010/2012 Supported by long- term agreements with Shell & BG Elba Island

Summary: Southern Pipelines Solid market position Recent rate case settlements Significant growth projects

Q&A

Review of Power Business

2004-20061 Power Plant Sales Domestic power plants Asian power plants European power plants Turbines and other Restructured contract assets Total closed Pending Power sales Asia Europe Central America2 Total pending Proceeds Associated Debt Sales program exceeds expectations $ 833 374 47 74 142 $ 1,470 $ 109 39 141 $ 289 $ 171 - - - 1,494 $ 1,665 112 ($ Millions) 1As of January 17, 2006 2Two additional plant sales in progress

Remaining Domestic Power Plants Midland Cogeneration Ventures Berkshire (merchant) CDECCA (merchant) Remaining investment in 3 plants-$0 Net MW 693 146 62

Brazil Power Bolivia-to-Brazil Pipeline Ownership: 8% Porto Velho (404 MW) Ownership: 50% Argentina-to-Chile Pipeline 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 ceased payments in January 2005; arbitration decision by June if negotiated settlement not reached 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 International arbitration is ongoing due to non-payment Actively pursuing resolutions

Review of Exploration & Production Regions

International

International Division Overview Fast-track Camamu oil development Execute strategic oil exploration program Target higher impact opportunities Solid organic growth outlook Create growth over a longer time horizon

Rio de Janeiro Balanced E&P Portfolio in Brazil 430,000 net acres = 82 GOM blocks Potiguar production with upside El Paso operated Camamu oil development Balanced shelf and deep water exploration Oil focus Camamu-Almada 1 Development Block 5 Exploration Blocks Potiguar 2 Production Blocks 3 Development Blocks 2 Exploration Blocks Espirito Santo 1 Exploration Block Santos 1 Development Block

2006 Capital Summary: International Exploration Production Development Capitalized G&A 39.15 23.5 17.4 6.96 Balanced spending program Near-term impact 2 production wells Camamu phased development Long-term impact 7 exploration wells Exploration 45% Production 27% Development 20% Cap. G&A 8% Capital Budget: $90 MM

Pescada-Arabaiana Fields 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 Net 58.2 61 58.1 41.1 55.4 52.9 52.1 52 49.9 55.7 51.2 51.2 23.2 24.5 24.3 25.2 25.9 24.3 23.6 24.3 25.4 25.6 24.9 24.5 Gross 81 84.8 80.8 57.2 77.1 73.5 72.4 72.3 69.4 77.4 71.2 71.2 72.9 76.8 76.2 79.2 81.2 76.4 74.1 76.3 79.8 80.4 78.3 76.8 2005 Activity Stable production 3 recompletions 2006 Program 1 recompletion 2 development wells 1 exploration well PDP PDNP PUD 21 13 46 PUD 46 Bcfe PDP 21 Bcfe PDNP 13 Bcfe Total: Net 80 Bcfe Rio de Janeiro

Camamu Basin: Phased Oil Development MOPU FSO Tanker 2006 Program FEED, MOPU fabrication and mobilization Drill 2 exploration wells to assess upside Economics: PVR: 1.25 F&D: $5.00/boe Unrisked reserve potential: 50 MMBOE Rio de Janeiro Phase I Cavala Development 100% WI High pour point oil 10 Prod / 7 Inj. - Cavala 2 Sardinha gas wells 1st production - 4Q 2007 2006 2007 2008 2009 2010 Camamu Phase I 0 2.2 12.4 13.3 12.6 Peak Rate: 13 Mboe/d 122

Phase II: Exploration Gross risked reserve potential: 19 MMBO WI: 100% Pc: 34% PVR: 1.3 TD: 8,857' WD: < 154' Spud: 2Q 2006 TD 3464 m TD 7,940' BAS-64 BAS-73 BAS-74 TD 2556 m Conservative OWC (-7,940' SS) Top Sergi reservoir W SW E Vsh ResD SwMS Vsh ResD SwMS Vsh ResD SwMS Upside OWC (-7,809' SS) DST 797 bopd DST 1,250 bopd DST 412 bopd DST trace oil DST 1,400 bopd DST oil & mud DST trace oil Upside wedge NE Cacau Area 1 Cavala North (19 MMBO) (75 MMBO) Cavala N POD area 3D survey outline 3D survey outline -2380 m ss -2380 m ss -2420 m ss -2420 ss -2420 m ss -2380 m ss -2420 m ss -2380 m ss -2420 m ss -2420 m ss -2380 m ss -2380 ss -2380 m ss -2380 m ss B B' Cacau-1 BAS-64 BAS-64 BAS-73 BAS-73 BAS-74 BAS-74 1 2 3 seismic Cavala North Development (BAS-64) 50 MMBOE [including Sardinha] 1,350 acres (at -2,380 m ss / conservative OWC) 1 3 km Cacau Prospect

Gross risked reserve potential: 16 MMBO WI: 100% Pc: 34% PVR: 1.3 TD: 7,546' WD: < 154' Spud: 2Q 2006 Phase II: Exploration Proven Analog: Canapu Field MDB discovery (El Paso) (Proven regional MDB channel sand upside) Canapu seismic Oil charged MDB channel sand 1 3 km BAS-64 Cavala N POD area BAS-73 BAS-74 MDB Prospects Sergi Prospects Cajah-1 Cacau-1 Cajah Prospect

Espirito Santo Basin: Exciting New Trend Gross unrisked reserve potential: 75 MMBOE WI: 35% PBR op 65% Pc: 17% PVR: 1.37 TD: 12,993' WD: 2,100' Spud: 2Q 2006 Bia. Golfinho Rio de Janeiro Espirito Santo Golfinho Field 450 MMBO 3P (2003 PBR) 3,996' WD Extended DST 20k bopd Light oil potential analogous to Petrobras' major Golfinho discovery

Large Inventory of Opportunities 8 exploration blocks 32 prospects/leads 14 Potiguar 14 Camamu 4 Espirito Santo 167 MMBOE Net Risked Potential 42 MMBOE Net Proven Reserves

Building Future Growth Brazil: Solid platform Balanced portfolio EP operates key oil development asset Potential to double production contribution over 3-year timeframe Foundation to add new core areas

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

GOM/S. Louisiana Overview Focus on efficient operations Execute a medium-risk drilling program Provide exposure to high-reward exploration Continue to develop inventory Hold production volumes with development capex; grow through exploration

Major Acreage Position SLA Position Acres Leased 28,000 Acres Optioned 72,700 El Paso Acreage Four Star Acreage GOM Position Total El Paso HBP El Paso Op HBP Other Op Primary Term Leases 192 60 59 73 Blocks 186 59 59 68 El Paso Operated Structures 85 5th largest net acreage position on the shelf

GOM Seismic Coverage 60,000 + sq. mi. GOM 3-D 3900 sq. mi. S. La. 3-D Extensive proprietary reprocessed seismic 3D Seismic Traces Reprocessed by Vendors Proprietary Reprocessed El Paso Leases

2005 Drilling Results 11 wells 73% success rate $113 MM net capital Generated 1.19 PVR

Capital: $50 MM 64 Projects 2005 Production: 7.7 Bcfe 2005 Production Enhancements Net MMcfe/d Recompletions and Capital Workovers Hurricane Impact

Production Profile: GOM/SLA 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 ITS 152.5 186.2 195.1 191.3 184.6 185.7 194.3 209 214.1 236.1 245.2 Stub 70.4 90.7 130 135 148.2 174.3 163.3 154.2 146.6 140.4 138.7 133.9 127.9 123.2 116.4 Base 246.3 225.8 224.7 221.3 224.3 208.3 189.1 183.4 108.7 70.4 90.7 130 135 148.2 174.3 163.3 154.2 146.6 140.4 138.7 133.9 127.9 123.2 116.4 2006 Capex Base MMcfe/d Hurricane Impact 2006 Volume Growth of >25%1 1December 2005 vs. December 2006E; excludes impact of hurricanes

West Cameron Discoveries 176 feet of net gas pay 54% working and net revenue interests (MMS royalty relief) Anticipated initial rate 20 MMcfe/d gross PUD location currently booked 43 feet of net gas pay 30% working and net revenue interests (MMS royalty relief) Anticipated initial rate of 40 MMcfe/d gross Potential updip location West Cameron 75 West Cameron 62 2000 Ft 2000 Ft

West Cameron 62/75 Platform

South Louisiana: Successful Leveraging Successful Dry Drilling Catapult Seismic Option Area 3,600 sq. mi. of seismic Promoted 8 prospects 15 remaining prospects

Economic Impact Results to date: Long Point #2 and Cane Ridge in progress Pre drill PVR unpromoted Pre drill PVR promoted Pc Net result Net capital savings Post drill PVR 0.9 3.1 17% Dry hole $4.9 MM 0 0.9 3.6 23% 7.2 MMcfe/d 7.4 Bcfe $3.9 MM 2.7 Little Bay Long Point #1

Long Point Discovery Logged 116 gross feet of pay Tested at a rate of 41 MMcfe/d Currently drilling first offset PUD location updip Deeper Planulina Prospect will be tested later this year Siph D Sand Planulina Sand Net D&C: $ 6.8 M Net Risked Mean Bcfe: 6.7 PVR: 1.7 Long Point #2

2006 Capital Summary: GOM/SLA Drilling Equipment Enhancement Seismic Leasing P&A 146 18 46 4 9 16 Seismic P&A Leasing 2% 4% 7% Production Enhancement 19% 87% of 2006 Capital dedicated to reserve and production growth Capital Budget: $240 MM Equipment 8% Drilling 60%

2006 Drilling Program: By Area Exploration and development capital split evenly Promote on 12 of 19 exploration wells Average predicted commercial success of 51% Excluding high risk promoted wells increases Pc to 67% Total Wells: 29 Total Net Drilling Costs: $144 MM Gulf of Mexico South Louisiana Exploration Avg MD: 19,875' $20 MM 9 Wells (6 carried to casing pt) Development Avg MD: 16,166' $11 MM 3 Wells Exploration Avg MD: 16,229' $52 MM 10 Wells Development Avg MD: 10,687' $61 MM 7 Wells

2006 GOM Drilling Program Avg. Depth 10,687' 16,229' Total Wells 7 10 Avg. PC (%) 83 44 Drilling Development Exploration Avg. Mean Reserves 8,875 25,900 Avg. PVR 1.47 2.43

2006 GOM Drilling Program & Inventory Four year inventory at 2006 funding levels Drill depths range from 7,300'-21,000' Additional prospects being generated in core trends New trends could add significant impact Avg. Depth 10,687' 16,229' 16,175' Total Wells 7 10 89 Avg. PC (%) 83 44 42 Drilling Development Exploration Current inventory Avg. Mean Reserves 8,875 25,900 Avg. PVR 1.47 2.43

2006 South Louisiana Drilling Program 3-D Seismic Coverage 3,600 Sq. Mi. Avg. Depth 16,166' 19,875' Total Wells 3 9 Avg. PC (%) 75 29 Drilling El Paso Operated Outside Operated Avg. Mean Reserves 3,350 2,875 Avg. PVR 1.43 2.57

2006 South Louisiana Drilling Program & Inventory 3-D Seismic Coverage 3,600 Sq. Mi. Avg. Depth 16,166' 19,875' 18,333' Total Wells 3 9 15 Avg. PC (%) 75 29 25 Drilling El Paso Operated Outside Operated Current Inventory (to be Promoted) Avg. Mean Reserves 3,350 2,875 Avg. PVR 1.43 2.57

Successful Results Three new field discoveries Solid production enhancements Strong future prospect inventory Hurricane recovery efforts ongoing Projected strong 2006 economic program

Texas Gulf Coast

Texas Gulf Coast Overview Continue lower-risk shallow development Predictable and repeatable results Leverage acreage position for higher-risk exploration Focus on operational challenges and opportunities Provide stable production base with medium risk exploration exposure

Texas Gulf Coast Region Vicks/Frio Wilcox Total 146,000 112,000 258,000 105,000 82,000 187,000 Gross Net Acreage 3D: >11,000 square miles 2D: >50,000 linear miles Seismic Coverage EPPC leases Large leasehold position in multi-pay areas

2005 Drilling Results 11 wells 82% success rate $45.4 MM capital Generated 0.68 PVR 7 wells 100% success rate $24.9 MM capital Generated 1.65 PVR 1st Half 2nd Half Second half success led to full year PVR of 1.02

Recreating TGC Detail work: Mapping and reservoir analysis Focus on risk analysis and play potential Infill projects established new opportunities Success in Wilcox Enhancements via PRIDE program 2nd Half 2005

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 ITS 100 100 100 100 100 100 100 100 100 100 100 182 182.1 176.6 175.4 181.5 178.1 182.4 192.8 190.5 200.8 203.3 213.9 213.4 Stub 100 100 100 100 100 100 100 100 100 193.5 183.9 182.6 177.5 171.2 165.7 161.9 157.7 153.6 150.3 146.5 143.1 139.8 136.7 133.7 Base 224 230.5 228.5 227.2 230.5 207.6 203.8 194.4 200 192.7 183.3 182.6 177.5 171.2 165.7 161.9 157.7 156.6 150.3 146.5 143.1 139.8 136.7 133.7 Production Profile: TGC 2006 volume growth of >15%1 MMcfe/d Base 2006 Capital 1December 2005 vs. December 2006E

Texas Gulf Coast Region Texas Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000' EPPC leases

Texas Gulf Coast Region Texas Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000' Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000' EPPC leases

Texas Gulf Coast Region Monte Christo Acreage: 15,313 net Wells: 5 in 2006 Up to 12 additional locations Avg TD: 10,000' Texas Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000' Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' EPPC leases Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000'

Texas Gulf Coast Region Jeffress Area Acreage: 30,447 net Wells: Up to 10 in 2006 +-11 contingent locations Avg TD: 11,000' Monte Christo Acreage: 15,313 net Wells: 5 in 2006 Up to 12 additional locations Avg TD: 10,000' Texas Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000' Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000' EPPC leases

Monte Christo Jeffress Bob West Victoria UGC Frio Other 28 23 4 15 23 7 2006 Capital Summary: TGC New Drilling Siesmic Leasing Equipment New ITS PVD ITS 54 5 5 6 30 Drilling 54% Seismic 5% Leasing 5% Equipment 6% Production Enhancements 30% Bob West 4% Other 7% Monte Cristo 28% Jeffress 23% Victoria 15% Upper Gulf Coast/Frio 23% Capital Budget: $180 MM

Texas Gulf Coast Region Texas Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000' EPPC leases EPPC leases

Bob West Field: Starr County Acreage: 14,103 net Wells: 4 wells in 2006 +/- 2 additional locations TD: 10,000'-12,000' Cost/Well: $5.8 MM PVR: 1.3 Reserves: 2-4 Bcfe/well WI: 48% USA Pad 1 Locations USA Pad 2 Locations Future Locations

Texas Gulf Coast Region EPPC leases EPPC leases Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000' Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000'

Typical Wilcox Well 10,500' 11,000' 14,000' U Wilcox (Klimitchek/Sralla) Well cost: $ 4 MM Reserves: 1 Bcfe M/L Wilcox (Renger/Sralla) Well cost: $ 4 MM Reserves: 1 Bcfe Ewers/Meine (Renger/Klimitchek) Well cost: $ 5.7 MM Reserves: 1.5 Bcfe Identifying high quality reservoirs in previously unrecognized section PVR ranges from 1.2 to 1.6 Avg. 3-5 Bcf /well Multiple objectives reduce risk Sand Resistivity (HC Indicator) 161

Future Wilcox Trend Opportunities Well situated in multi-pay areas Promote a portion of high-risk opportunities Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000' Avg. Cost/Well: $5.7 MM PVR: 1.4 Reserves: 1-4 Bcfe/well WI: 92% Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' Avg. Cost/Well: $6.7 MM PVR: 1.2 Reserves: 2-4 Bcfe/well WI: 75% Operated wells EP Leases Speaks/Hardy's Creek Dry Hollow/Big Holler/Hope 162

Wilcox Discovery 2005 Drilling Success 1 well ready to drill Rochelle / Massive / Ewers EPPC Leasehold Outlines Renger #1 Renger #3 Renger #2 Lavaca County Renger 1,2,3 ~15-20 Bcfe (gross) >25 MMcfe/d Klimitchek

2005 Drilling Success 1 well ready to drill Rochelle / Massive / Ewers EPPC Leasehold Outlines Klimitchek Prospect If we find shallow pay in Rochelle SS horizons... PTD: 14,600' DHC: $3.4 MM WI: 87.5% D&C: $5.7 MM Est. mean prospect reserves: 21 Bcfe Prospect Pc (commercial success): 40% PVR 1.3 Lavaca County Renger 1,2,3 ~15-20 Bcfe (gross) >25 MMcfe/d Klimitchek

...18 add'l upside locations Klimitchek Upside Potential 2005 Drilling Success 1 well ready to drill Rochelle / Massive / Ewers EPPC Leasehold Outlines Lavaca County Renger 1,2,3 ~15-20 Bcfe (gross) >25 MMcfe/d Klimitchek

Texas Gulf Coast Region Texas EPPC leases EPPC leases EPPC leases Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000' Monte Christo Acreage: 15,313 net Wells: 5 in 2006 Up to 12 additional locations Avg TD: 10,000' Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000'

South Texas 8,500' 12,000' 19,000' Frio Well cost: $1.3 MM Reserves: 1.1 Bcfe Upper Vicksburg Well cost: $2.0 MM Reserves: 2.0 Bcfe Lower Vicksburg Well cost: $7.6 MM Reserves: 5.3 Bcfe Sand Resistivity (HC Indicator) Now working shallower opportunities PVR ranges from 1.2 to 1.6 Similar reserve potential as deep with less risk and cost 167

TGC Region: Frio/Vicksburg Play Acreage: 15,313 net Wells: 3 in 2005, up to 12 in 2006; +-15 contingent locations Avg. TD: 10,000' Avg. cost/well: $2.0 MM PVR: 1.4 Significant shallow potential on existing acreage Promote a portion of high-risk opportunities Monte Christo 168

Vicksburg Success 2005 Drilling Success 5 wells ready to drill EPPC Leasehold Outlines H. Ranch 36 H. Ranch 47 H. Ranch 60 H. Ranch 42 Monte Christo Monte Christo Monte Christo Monte Christo U. Vicksburg U. Vicksburg L. Vicksburg M. Vicksburg 1.0 0.9 2.3 1.4 6.1 9.5 11.0 3.0 Recompletions Field Formation Capex ($MM) Initial Produciton (MMcf/d) Monte Christo Field HR-75 141 ft net pay 1.0 MMcfe/d HR-71 150 ft net pay IP 1.2 MMcfe/d

Vicksburg Upside 2005 Drilling Success 5 wells ready to drill 12 add'l upside locations EPPC Leasehold Outlines HR-71 150 ft net pay IP 1.2 MMcfe/d HR-75 141 ft net pay 1.0 MMcfe/d H. Ranch 36 H. Ranch 47 H. Ranch 60 H. Ranch 42 Monte Christo Monte Christo Monte Christo Monte Christo U. Vicksburg U. Vicksburg L. Vicksburg M. Vicksburg 1.0 0.9 2.3 1.4 6.1 9.5 11.0 3.0 Recompletions Field Formation Capex ($MM) Initial Produciton (MMcf/d) Monte Christo Field

Texas Gulf Coast Region Texas EPPC leases Monte Christo Acreage: 15,313 net Wells: 5 in 2006 Up to 12 additional locations Avg TD: 10,000' Dry Hollow/Big Holler/Hope Acreage: 9,458 net Wells: 2 in 2006 Avg. TD: 17,000' Bob West Acreage: 14,103 net Wells: 4 in 2006 +/- 2 add'l locations TD: 12,000' Jeffress Area Acreage: 34,730 net Wells: Up to 10 in 2006 +-11 contingent locations Avg TD: 11,000' Speaks/Hardy's Creek Acreage: 10,174 net Wells: 4 in 2006 Avg. TD: 14,000'

Jeffress Area Top of T Sand (Vicksburg) Depth Map 11 wells add'l upside (Frio - Vicksburg) 10 wells ready to drill (Vicksburg) EPPC Leasehold Outlines Acreage: 34,730 net Avg TD: 11,000' Avg Cost/Well: $2.5 MM PVR: 1.4 Reserves: 1-3 Bcfe/well WI: 65% Multiple contingent locs. Hidalgo County 0 6,000 12,000 Feet

Exploration Potential 1,500 sq. miles of reprocessed seismic Two wells drilled to date One success with three development locations ready for 2006 Exploratory well 1Q2006 with three contingent development locations New team evaluating with high-end applications EPPC leases Beast Project

Saga Development PTD: 10,600' WI: 100% D&C: $3.0 MM DHC: $1.3 MM Est. Mean Prospect Reserves: 7 Bcfe Prospect Pc (commercial success): 80% PVR: 1.33 Saga-1 IP 5 MMcf/d La Copita Field, Starr County 3 Phase I wells

Pacesetter Drilling Example Targeting continuous improvement 5 days = 26% reduction

Daskam Prospect: Starr County PTD: 9,800' WI: 100% D&C: $3.0 MM DHC: $1.3 MM Est. Mean Prospect Reserves: 7 Bcfe Prospect Pc (commercial success): 50% PVR: 1.25 Reavis Farms No.1 * New Gas Discovery @ 9,250' 3 Add'l Locations

Frio Play Acreage: 6,770 net acres Wells: 4 in 2006 Avg. TD: 18,000' Avg. Cost/Well: $6 MM (net) PVR: 1.4 Additional prospects within play area being evaluated Reserves: 8-25 Bcfe/well Big Hill Inverness Troon Complex Troon Complex/Inverness

Regional Integration Project Deep Frio 3D Seismic Loaded Play Expectations Industry Activity Beast 3D Survey +/- 800 EP operated wells 3D: >11,000 square miles 2D: >50,000 linear miles Multiple Counties (~35,000 sq. mi.) N 178

Room to Run... Detail work on base properties New drill wells Existing well work Sidetracks Recompletions Workovers Exploration from regional data integration Running room in mature area

Onshore

Onshore Overview Predictable, repeatable drilling program Demonstrated growth profile Large inventory of opportunities Long-lived stable production Provide consistent organic production and reserve growth

Onshore Strategy Expand unconventional production base Expand tight gas production base Expand opportunity portfolio Don't focus exclusively on natural gas Mitigate cost escalation through efficiency improvements Organic coal bed methane production growth of 18% Increased East Texas/North Louisiana production 52% Added 464 future locations (after drilling 453 wells in 2005) Increased oil production 129% 26% total cycle time improvement (well spud to first sales) Strategy 2005 Scorecard

Total Onshore 327 MMcfe/d1 453 wells drilled in 2005 1,708,000 net acres 2,958 identified locations Extensive Portfolio 1December 2005; excludes 71 MMcfe/d from FSOG El Paso Acreage Four Star Acreage New Albany Shale 112,000 net acres Rockies 44 MMcfe/d1 74 wells drilled in 2005 400,000 net acres 592 identified locations Raton 77 MMcfe/d 125 wells drilled in 2005 605,000 net acres 668 identified locations Arkoma/Mid-Cont 29 MMcfe/d1 64 wells drilled in 2005 120,000 net acres 450 identified locations Black Warrior 62 MMcfe/d 115 wells drilled in 2005 160,000 net acres 667 identified locations Arklatex 115 MMcfe/d1 75 wells drilled in 2005 128,000 net acres 581 identified locations 183

Onshore: Predictable Performance 2005 Plan 2005 Results 2006 Plan No. of Wells Drilling Capital ($ MM) Production (MMcfe/d) PVR 486 243 30 1.24 453 263 44 1.23 548 405 61 1.26

Onshore Cycle Time Scorecard Arkoma Arklatex Black Warrior Raton Rockies 53 60 87 86 58 27 43 64 72 44 26 17 23 14 14 54 76 84 109 32 355 1,409 1,292 1,932 1,526 454 6,613 2004 Avg. Days 2005 Avg. Days '04 vs. '05 Reduced Days 2005 Drilled Wells Incremental Production Days Fav./(Unfav.) Cycle time = well spud to first sales

2006 Onshore Capital Distribution Drilling (Non-Proved) Recompletions Equipment Leasing & Seismic Onshore 391.972 36.822 32.53 12.739 Capital Budget: $490 MM Recompletions 8% Leasing & Seismic 3% Equipment 7% Drilling 82% *Includes Mid-Continent / New Albany Note: Capital on Medicine Bow acquired assets represents 20% of total capital Arkoma Black Warrior Raton Rockies Arklatex Onshore 50 45 65 117 203 Arkoma* 11% Black Warrior 9% Raton 14% Rockies 24% Arklatex 42%

Onshore: Continuing Growth 2006 Base Four Star 2006 Capital 2006 volume growth of >15%1 1December 2005 vs. December 2006E

Expanding Unconventional Position El Paso Acreage Four Star Acreage Rockies CBM 103,350 undeveloped net acres 2 new pilots scheduled for 2006 Countyline Big George: 52 wells drilled 2005 (19%) Currently - 8 MMcf/d Raton Basin CBM 500,000 undeveloped net acres 125 wells drilled - 2005 Currently 77 MMcf/d Arkoma Basin CBM 44,000 undeveloped net acres 63 wells drilled - 2005 Currently 19 MMcf/d New Albany Shale 110,000 undeveloped net acres 3 exploration wells drilled - 2005 1st pilot on production 12-05 B. Warrior Basin CBM 78,000 undeveloped net acres 115 wells drilled - 2005 Currently - 62 MMcf/d San Juan Basin (Four Star) 33,450 total net acres Currently 39 MMcf/d 188

Increasing Unconventional Base 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 Non-Conventional 129.0527162 127.0437289 147.1985245 146.8201865 143.149208 152.1172844 163.5483064 166.9579025 Conventional 94.41654926 95.37231616 93.16084855 93.70936471 100.7522221 141.387802 163.1037345 169.701408 Arkoma Shale Gas BWB Raton Rockies 2006 Production 12.3 0.9 36 48.2 2.6 2006 Production 170 MMcfe/d Raton 48% Rockies 3% Arkoma 12% Shale Gas 1% BWB 36% Excludes FSOG

Vermejo CBM Growth 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 Actual 54 55.6 61.1 64.6 65.4 69.2 74.5 77.7 2006 Plan Actual

Raton Horizontal Update 20 horizontal extensions from existing vertical producers completed with a 500% average production increase 8 "grass roots" new wells drilled horizontally Drilled first stacked multi- lateral in 2005 12 multi-laterals and 12 horizontal extensions planned for 2006 Coals Raton Coals Vermejo

1/1/2004 2/1/2004 3/1/2004 4/1/2004 5/1/2004 6/1/2004 7/1/2004 8/1/2004 9/1/2004 10/1/2004 11/1/2004 12/1/2004 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 Actual 2.7 2.8 2.5 2.5 2.6 2.6 2.6 2.8 2.7 3.4 3.7 3.3 3.5 3.7 4.1 4.7 5.6 6.9 8.1 10 10.6 11.3 11 10 Horizontal Recompletions First horizontal lateral Average rate pre-work: 158 Mcfd / well Average initial rate post-work: 802 Mcfd / well 20 laterals completed Raton

Room to Run Producing Well Proposed 2006 Future Location 668 future locations 2,500' avg. TVD 3,000' avg. lateral length 2006 vertical well cost: $0.5 MM 2006 triple-lateral well cost: $1.7 MM Raton 193

Hartshorne CBM Growth 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 Actual 11.4 12 13.8 12.7 14.2 16.8 21.2 20.1 2006 Plan Actual

Illinois Basin: New Albany Shale Avg. TVD: 2,000' Avg. lateral length: 4,500' 2006 avg. well cost: $900K Avg. WI: 50% Illinois Basin Biogenic Gas Fairway Estimated GIP - 80-160 Tcf* El Paso position 225,000 gross acres Quicksilver Activity Corydon/Laconia Fields *National Petroleum Council 1980-1992

Emerging Unconventional Opportunity 2005 Activity 7 horizontal wells 50% industry partner Initial pilot to sales 2006 Plans 5 exploratory wells 13 development wells Significant potential: 225,000 gross acres Current development on 320 acre spacing 6 Miles 2005 Exploratory Wells 2006 Exploratory Wells Initial Pilot Area 4 Producing Wells New Albany Shale

Expanding Tight Gas Position El Paso Acreage Four Star Acreage New Albany Shale 112,000 net acres Rockies 44 MMcfe/d1 74 wells drilled in 2005 400,000 net acres 592 identified locations Raton 77 MMcfe/d 125 wells drilled in 2005 605,000 net acres 668 identified locations Arkoma 29 MMcfe/d1 64 wells drilled in 2005 120,000 net acres 450 identified locations Black Warrior 62 MMcfe/d 115 wells drilled in 2005 160,000 net acres 667 identified locations Arklatex 115 MMcfe/d1 75 wells drilled in 2005 128,000 net acres 581 identified locations 1December 2005; excludes 71 MMcfe/d from FSOG 197

Re-establishing East Texas Position East Texas 43 MMcfe/d 4 rig 2006 program - 71 wells 195 identified locations North Louisiana 72 MMcfe/d 2 rig program - 45 wells 384 identified locations Texas Arkansas Louisiana Ming's Chapel Minden Stockman Shongaloo Bear Creek Complex Holly Arklatex

1Q05 2Q05 3Q05 4Q05 Actual 19.9 22.2 26.3 28.4 East Texas Acquisition Closed February 2005 100% success on 37 wells drilled to date Improved 1Q to 4Q cycle time (spud-first sales) from 67 to 38 days Reduced lifting cost from $0.33 to $0.29/Mcfe 2005 exit rate of 30 MMcfe/d

East Texas Acquisition Update Reserves (Bcfe) Cost / (Cash Flow) ($ MM) $/Mcfe Balance at Closing Production Revisions/2005 Program Balance at 1/1/2006 107 (8 ) 19 118 $ 179 (73 ) 51 $ 157 $1.67 9.26 2.68 $1.33

Delivering Results Avg. depth: 10,900' Avg. WI: 95% Well cost: $1.8 MM 36 wells drilled to date 100% success rate 2005 PVR: 1.25 Avg. reserves: 1.1 Bcfe/well Increased production from 17 to 28 MMcfe/d 183 identified locations Producing Well Proposed 2006 Future Location Minden Field

Idaho Colorado Utah Wyoming House Creek Kaye-Teapot Altamont - Bluebell Azurite County Line Hay Rockies Position

8/1/2004 9/1/2004 10/1/2004 11/1/2004 12/1/2004 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 Actual 64.74 238.4 295.45 276.02 146.76 325.41 401.37 403.1 372.32 438.2 581.36 692.22 670.43 923.72 1024.98 1634.76 1631.97 Producing Well Proposed 2006 Future Location House Creek Parkman Program Parkman Horizontal Program 2005 Drilling: 13 wells Rassbach 12-5H IP 336 bopd Innes Federal 12-17H Drilled in 23 days Cost $1.2 MM Date of Acquisition

Altamont / Bluebell 500 sq. mi. field area 2006 program 1 rig - 8 wells 85% avg. interest 12,500' avg. depth $4.7MM avg. well cost Producing Well 2005 Wells Proposed 2006 Future Location Brotherson 2-24-B4 IPP 650 BOPD Baker-Ute 2-34C6 IPF 905 BOPD; 2MMCFGPD Bodrero 2-15-B3 IPP 220 BOPD Tew 1-15A3 ESP Conversion 400 BOPD

Organic Oil Growth 20 Recompletions $5.5 MM Current uplift: 800 bopd 9 Enhancement projects $2.0 MM Current uplift: 380 bopd 3 New wells drilled $10 MM Avg. gross IP: 590 bopd Altamont Bluebell

Consistency 2005 Growth 29% organic production increase Acquisitions integrated Predictable Program 453 wells with 99% success Efficiency Minimized inflation impact with focus on optimization Reduced unit lifting cost by 5% ($0.03/Mcfe) Reduced cycle time (spud to first production) adding more than 6,500 producing days

Q&A

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 reviewed 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. The company defines EBITDA as EBIT plus Depreciation, Depletion and Amortization. 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 and EBITDA , 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. We also believe that debt holders commonly use EBITDA to analyze company performance. Net Debt is defined as El Paso's total Financing Obligations as disclosed on the company's consolidated balance sheet net of cash and cash equivalents. Net Debt is an important measure of the company's total leverage. Investor's should be aware that some of El Paso's cash is restricted and not available for debt repayment . Total Liquidity is defined as cash that is easily available for general corporate purposes and available capacity under El Paso's $3 billion credit agreement and El Paso's $300 million borrowing base credit facility. Total Liquidity demonstrates the company's ability to meet current obligations and commitments. Per-unit total 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 measurements.

Net Debt Reconciliation Total debt at 9/30/05 Total cash and cash equivalents Outstanding net debt at 9/30/05 Total estimated debt at 12/31/05 Total estimated cash and cash equivalents Estimated net debt at 12/31/05 $ 17.9 0.9 $ 17.0 $ 18.2 2.1 $ 16.1 $ Billions

2006 Core Earnings and Cash Flow Reconciliation EBITDA DD&A EBIT Interest Taxes at 38% Net income Non-cash adjustments (90%) DD&A Non-cash taxes Working capital changes & other Operating cash Dividends Maintenance capital Discretionary cash Growth capital Free cash EBIT 211 $3,455-$3,560 1,100 $2,355-$2,460 1,275 410-450 $670-$735 $1,100 370-405 415-425 $2,555-$2,665 $110 1,275 1,170-1,280 770 $400-$510 $0.95-$1.05 $3.37-$3.51 EPS Cash Per Share $ Millions, Except Earnings & Cash Per Share

Historical EBITDA Reconciliation Net loss Discontinued operations, net of income taxes Loss from continuing operations Income taxes (benefit) Loss before income taxes Return of preferred interests of consolidated subsidiaries Interest and debt expense EBIT DD&A EBITDA $ (986 ) 14 (1,000 ) (269 ) (1,269 ) 16 1,412 159 1,129 $ 1,288 Last 12 Months Ended 9/30/05 ($ Millions)

Production Related Derivative Schedule See El Paso's Form 10-Q filed 11/7/05 and Form 10-K/A filed 6/15/05 for additional information on the company's derivative activity 1Hedge price and cash price are identical for 2007-2012 Note: 2006 and beyond positions as of September 30, 2005

Maintenance Burden as Percent of Discretionary Cash Flow Key Assumptions "Maintenance Capital" is defined as capital required to replace 100% of production at an assumed F&D rate Actual F&D data used for 2004 and 2005; 2006 assumed equal to 2005 "Discretionary Cash Flow" is defined as operating cash flow, excluding changes in working capital, and includes interest expense assuming debt of $0.75/Mcfe of reserves at 8.5% interest Production (Bcfe) Drillbit + acquisition F&D Maintenance capital Discretionary cash flow 298 $3.61 1,075 1,143 94 % 280 $ 2.41 675 1,175 57 % 305 $ 2.41 735 1,506 49 % 2004 2005 2006 Maintenance Burden Calculation Note: JPM Equity Research analysis assumes $7.80 price deck in 2006; EP projections used $8.00; all EP numbers include equity interest in FSOG

Reserve Reconciliation Beginning balance 12/31/20041 Production Sale of reserves in place Purchases of reserves in place Extensions, discoveries, and other Revisions of previous estimates Ending balance 12/31/20052 Four Star Oil & Gas 2,181 (271 ) (25 ) 277 242 11 2,415 253 Total EPPC Equivalent Reserves (Bcfe) 1HH = $6.22/MMBtu, WTI = $43.45/Bbl 2HH = $10.08/MMBtu, WTI = $61.04/Bbl

2006 Analyst Meeting January 18, 2006