EXHIBIT 99.1

Williams Analyst Conference Call 2003 Results February 19, 2004

Forward Looking Statements Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" with in the meaning of Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward-looking words, such as "anticipate," believe," "could," "continue," "estimate," "expect," "forecast," "may," "plan," "potential," "project," "schedule," "will," and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: ·Our ability to divest successfully certain assets and our ability to identify and achieve cost savings measures, which may be dependent on factors outside of our control; ·Our ability to timely divest our wholesale power and energy trading business which may be dependent on factors outside of our control; ·Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; ·Because we no longer maintain investment grade credit ratings, our counterparties might require us to provide increasing amounts of credit support; ·Electricity, natural gas liquids and gas prices are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses; ·We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; ·Our risk measurement and hedging activities might not prevent losses; ·Our operating results might fluctuate on a seasonal and quarterly basis; ·Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; ·Legal proceedings and governmental investigations related to the energy marketing and trading business; ·Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; ·Our ability to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas; ·The different regional power markets in which we compete or will compete in the future have changing regulatory structures; ·Our gas sales, transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities; ·We could be held liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; ·Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; ·Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; ·The continued availability of natural gas reserves to our U.S. and Canadian natural gas transmission and midstream businesses; ·Our gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; ·The threat of terrorist activities and the potential for continued military and other actions; and ·The historic drilling success rate of our exploration and production business is no guarantee of future performance. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Agenda 2003 Review Steve Malcolm 2003 Financial Review Don Chappel Business Unit Review and Outlook Exploration & Production Ralph Hill Gas Pipeline Doug Whisenant Midstream Alan Armstrong Power Bill Hobbs 2004-2006 Consolidated Outlook Don Chappel Summary Steve Malcolm Q&A

2003 Review Steve Malcolm President, Chairman & CEO

Strategy Commercial Natural gas assets in key growth markets where we enjoy the competitive advantages of scale, low-cost position and market leadership Financial Create and maintain adequate liquidity from all available sources to fully support business strategy De-leverage through combination of asset sales, refinancing, cost-cutting Develop balance sheet capable of supporting and ultimately growing business and value

Initiate & Stabilize Execute Restructuring Emerge Avoid bankruptcy Address liquidity crisis Restore customer and supplier confidence Complete asset sales Rationalize cost structure Manage liquidity De-lever Restore confidence of and gain access to capital markets Position company for integrated natural gas growth Optimize capital structure Capitalize on strategic position Measures of Success A Work in Progress

Asset sales program 90% complete $3.0 billion net proceeds in 2003; $6.1 billion since 2002 Rationalize cost structure 30% reduction in continuing ops SG&A costs; efforts continue Manage liquidity $2.3 billion in available cash and equivalents at year-end De-lever Net $2 billion decrease in debt in 2003 Will meet the March 15 retirement of remaining 9.25% notes Restore confidence of and gain access to capital markets Solid operating performance Restructuring Success Measures

Announced but not closed $265 million Alaska Refinery 1Q04 Identified for sale totaling $500-600 million Midstream Assets 2Q/3Q/4Q04 Western Canada Assets (Straddle Plants) 3Q04 Pending Asset Sales

Power Restructuring Outlook Actively pursuing full exit of power business Sold or liquidated nearly $600 million of power-related assets and contracts since June 2002 Agreed to terminate contract with Allegheny Managing in the interim to Reduce risk Generate cash Meet contractual commitments Exit timing and value uncertain Remaining positions complex Power markets have deteriorated Positive exit value in West; negative exit value in remainder Held Tutorial on November 21 to provide greater clarity

Focus on strong business performance Disciplined investment in core businesses Continued restructuring De-levering Complete asset sale program Cost reductions Power Position for future growth that creates economic value Path Ahead

2003 Financial Review Don Chappel, CFO

4Q03 4Q02 2003 2002 Income (Loss) from Continuing Ops.* ($97) ($151) $3 ($612) Income (Loss) from Discont. Ops. 31 (68) 254 (143) Effect of Accounting Change - - (761) - Net Loss* ($66) ($219) ($504) ($755) Net Loss / Share* ($0.13) ($0.44) ($1.03) ($1.63) Recurring Inc./(Loss) from Cont. Ops** $57 $47 $12 ($222) Rcr. Inc./(Loss) from Cont. Ops /Share** $0.11 $0.09 $0.02 ($0.43) 2003 Results * Includes gains and impairments on asset sales and prior period adjustments ** A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com. Dollars in millions (except per share amounts)

Income (Loss) from Cont. Ops. ($97) ($151) $54 Gains on Asset Sales (16) 2 (18) Impairments/Losses/Write-offs 131 253 (122) Debt Tender Expenses 67 - 67 Cal. Refund & Other Accrual Adj. 33 - 33 Other - Net - 2 (2) Less: Income Tax Provision 61 52 9 Recurring Income from Cont. Op. $57 $54 $3 Preferred Dividend - (7) 7 Rec. Inc. from Cont. Op. Avail. To Common $57 $47 $10 Recurring Income from Cont. Op/Share $0.11 $0.09 $0.02 4th Quarter Recurring Income from Continuing Operations 4Q03 4Q02 Difference Dollars in millions A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com.

Income (Loss) from Cont. Ops. $3 ($612) $615 Gains on Asset Sales (337) (220) (117) Impairments/Losses/Write-offs 279 728 (449) Expenses on Debt Tender 67 - 67 Income Related to Prior Periods * (105) - (105) Cal. Refund & Other Accrual Adj 33 - 33 Other - Net 45 110 (65) Less: Income Tax Provision (57) 138 (195) Recurring Income from Cont. Op. $43 ($132) $174 Preferred Dividend (30) (90) 60 Rec. Inc./(Loss) from Cont. Op. Avail. To Com. $12 ($222) $234 Rec. Income/(Loss) from Cont. Op/Share $0.02 ($0.43) $0.45 Full Year Recurring Income from Continuing Operations 2003 2002 Difference Dollars in millions * See Note 1 in 2Q 2003 10Q for description A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com.

2003 Segment Profit Reported Recurring 2003 2002 2003 2002 Gas Pipelines $555 $545 $581 $574 Exploration & Production 401 509 310 368 Midstream Gas & Liquids 286 183 319 309 $1,242 $1,237 $1,210 $1,251 Power** 134 (625) (25) (353) Other (50) 14 (10) (28) Segment Profit* $1,326 $626 $1,175 $870 Dollars in millions *Reported segment profit Includes gains and impairments ** Reported 2003 segment profit for Power includes income related to prior periods A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com.

2003 EBITDA Reconciliation 671 DD&A 29 Provision for Income Taxes 1,243 Net Interest Expense Dollars in millions ($504) Net (Loss)* $1,946 EBITDA* (254) Income from Disc. Operations 761 Cum. Effect of Change in Acct. Principle * Includes gains and impairments on asset sales and prior period adjustments

* Includes gains and impairments on asset sales and prior period adjustments **Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 2003 Segment Contributions * * Gas Pipes E&P Midstream Power Corp/Other Total Segment Profit (Loss) $555 $401 $286 $134 ($50) $1,326 DD&A 247 174 199 31 20 671 Segment Profit before DDA $802 $575 $485 $165 ($30) $1,997 General Corporate Expense (87) Investing Income* 78 Other Income (42) TOTAL $1,946

4Q03 2003 Beginning Cash* $3,431 $1,736 Cash Flow from Operations 75 770 Capital Expenditures/Investments (353) (1,107) LC Collateral 60 (388) Retirements (Debt & Pref. Stock) (1,221) (3,425) Asset Sales 174 2,983 Debt Proceeds 230 2,006 Other-Net (79) (257) Ending Cash* $2,318 $2,318 Restricted Cash $207 2003 Cash Information Dollars in millions * Includes cash for discontinued operations of $2.6 million at 12/31/03, $2.9 million at 9/30/03 and $85.6 million at 12/31/02

Debt Balances 2003 Debt Balance @ 12/31/02 (1), (2) $13,991 Debt Associated with Discontinued Operations (897) Debt Balance Adjusted for Disc. Oper. @ 12/31/02 13,094 Scheduled & Tendered Debt Retirements (1,742) Progeny Debt Payments (460) Accreted Capitalized Interest 69 Lehman/Berkshire Loan Prepayment (988) New Debt Issues (3) 2,006 Debt Balance @ 12/31/03 $11,979 Net Decrease in Debt $2,012 Net Increase in Cash (incl. Disc. Operations) $ 583 $2,595 Dollars in millions Avg. Cost 10.0% 7.7% (1) Debt is long-term debt due within 1 year plus long-term debt plus notes payable (2) Includes FELINE PACS (3) Includes $300MM junior subordinated debt issued to retire preferred stock

Enterprise Risk Management Margins & Ad. Assur. $281 $ 44 $202 - $527 Prepayments - 12 139 - 151 Subtotal $281 $56 $341 $ - $678 Letters of Credit 3 - 190 185 378 Total as of 12/31/03 $284 $56 $531 $185 $1,056 Total as of 12/31/02 $1,131 Change ($75) Corp./ E&P Midstream Power Other Total Estimated dollars in millions

Enterprise Risk Management Margin volatility (99% confidence interval) - liquidity requirement 30 days ($183) million 180 days ($324) million 360 days ($349) million Assumption: The margin numbers above consist of only the forward marginable position values, starting from February 2004. Does not include adequate assurance, prepayments or other spot monthly liquidity requirements.

Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associated with Spark Spread increase is consistent across all months. Cash flow ranges are not linear. 3 Assumes a non-correlated change in NGL processing spread (i.e. change in NGL price only). 1 2 3 Estimated dollars in millions

Business Unit Review and Outlook

Exploration & Production Ralph Hill, Senior VP

4th Quarter 2003 2002 2003 2002 Exploration & Production Segment Profit Segment Profit $50 $82 $401 $509 Includes (Gain)/Loss on Asset Sale - 3 (91) (141) Recurring Segment Profit $50 $85 $310 $368 Recurring segment profit declined due to expiration of Section 29 tax credits of $8 million in 4Q02 and $34 million in 2002 with remainder of decrease primarily due to lower volumes resulting from asset sales Dollars in millions

Exploration & Production 4Q/YE 2003 Accomplishments 4Q Increased Drilling Activity Piceance rig count increased to 8 rigs from 1 in 2Q San Juan added 1 drilling rig and 4 cavitation rigs Reversed volume decline during fourth quarter Completed backyard acquisition of working interest partner in Arkoma 2003 production replaced at a ratio of 254% 2003 drilling success rate of 99% Moved 412 Bcf from Probable to Proved Reserves, 2.7 Tcf total reserves at 12/31/03

Exploration & Production Proved Reserves Reconciliation -390 -186 +445

Proved + Probable Reserves Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 1553 264 690 171 Proved Reserves TOTAL: 2.7 Tcf Proved Exploration & Production 2003 Year End U.S. Reserves Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 3286 1558 948 229

2004 2005 2006 Segment profit $275-340 $350-450 $400-500 Annual DD&A $160-180 $195-225 $230-260 Capital spending $300-350 $400-450 $450-500 Production (MMcfed) 500-550 600-700 700-800 Dollars in millions Exploration & Production 2004-2006 Guidance

Horizontal Hartshorne CBM drilling Geographic extent of coal offers growth opportunities In-fill, field extension drilling Proprietary low-pressure gathering system constructed in 2002 Key characteristics 122 Bcfe total proved reserves 17 MMcf/d net production Leasehold 58,000 net acres 168 total wells, 90% operated 160 acre development spacing 2003 drilling success rate of 94% Exploration & Production Arkoma Basin Overview

Conventional and coalbed methane production Long life / slow decline wells Low risk in-fill drilling via downspacing and EIS Good pipeline infrastructure / market access Key characteristics 702 Bcfe total proved reserves 136 Mmcf/d net production Leasehold 94,000 net acres 714 operated and 1,400+ joint interest wells 2003 drilling success rate of 100% Exploration & Production San Juan Basin Overview

High potential, low-risk development play Low cost wells Typical well production Wyodak - 140 Mcf/d peak Big George - 400Mcf/d peak Key characteristics 257 Bcfe total proved reserves 114 MMcf/d net production Leasehold 1,021,400 gross/457,900 net acres 4,109 total wells, 50% operated 2003 drilling success rate of 99% 10,980 drilling locations Exploration & Production Powder River Basin Overview

660 Federal Well Permits issued to the industry post Record of Decision (ROD) Williams received 140 (21%) and partner 61 for total of 201(30% ) 74 of 140 wells spudded post-ROD 1,400 industry permits in the approval process; 352 for Williams and partner BLM's goal is to issue 3,000 permits per year, ongoing streamlining process Big George is now producing 118 MMcfd or 12% of Powder River Basin production Exploration & Production Powder River Basin - Update

Large gas-saturated, basin-centered gas trap High return/low risk economics Key characteristics 1.6 Tcfe total proved reserves 172 MMcf/d net production Leasehold 173,800 gross /129,900 net acres 2,500 drilling locations, > 10 yr inventory 802 total operated wells, high working interest 2003 drilling success rate of 100% 10 rigs operating, increasing to 12 rigs during the year Exploration & Production Piceance Basin Overview

Exploration & Production Basin Comparison

2004 - 80% hedged at $4.03 NYMEX 2005 - 47% hedged at $4.44 NYMEX 2006 - 40% hedged at $4.39 NYMEX Basis hedges in place to mitigate location risk Future hedging strategy will continue to be a function of Williams' portfolio Exploration & Production Hedging

Exploration & Production Challenges and Opportunities Challenges Pace of drilling permit approvals Rig availability Opportunities BLM committed to streamlining Williams has successfully obtained additional rigs Opportunity to increase drilling pace beyond planned rate Numerous backyard investment and acquisition opportunities

Conservative business strategy Investments are short time cycle, fast cash returns High-quality, low-risk reserve base History of high success, low finding costs Diverse producing basins, long term drilling inventory Significant probables and possibles inventory Low-cost, high-margin producer Experienced management team Talented work force Exploration & Production Platform for Growth

Gas Pipeline Doug Whisenant, Senior VP

Gas Pipeline Assets Transco Northwest Gulfstream (50% Ownership)

Gas Pipeline Segment Profit 4th Quarter 2003 2002 2003 2002 Segment Profit $148 $122 $555 $545* Includes Write-off projects - 5 25 19 Gulfstream Project completion fee - - - (27) Early retirement/realignment - - 1 15 Net gains/losses/impairments - 16 - 22 Recurring Segment Profit $148 $143 $581 $574 Dollars in millions * 2002 includes $26 million Transco rate case settlement and $27 million Gulfstream AFUDC

Gas Pipeline 4Q 2003 Accomplishments Northwest Evergreen Expansion placed into service 10/1/03 Columbia River Gorge Expansion placed into service 10/21/03 Rocky Mountain Expansion Project placed into service 11/30/03 Transco Trenton-Woodbury Expansion placed into service 11/1/03 South Central New Jersey Expansion, open season

Location Low cost provider Few expiring long-term contracts Customer credit quality Gas supplies System flexibility Gas Pipeline Strengths

THURSTON LEWIS GRAYS HARBOR TUMWATER PIERCE SUMNER KING SNOHOMISH SKAGIT WHATCOM Bellingham SUMAS MT VERNON SNOHOMISH Redmond Everett Seattle Existing 30" Mainline Proposed 26" Replacement Facilities CHEHALIS Jackson Prairie Storage Gas Pipeline Restore/Replace 26" Corrective Action Order Idle 26" mainline Sumas, WA to Washougal, WA Allows temporary removal of restrictions after testing Required to replace capacity within 10 years; expect to replace in 3 years Evaluate additional segments Cost recoverable through rates

Gas Pipeline FERC Issues Future Rate Cases No filing requirement until 2007 Transco filing possible pre-2007 26" Restore/Replace triggers Northwest filing Energy Affiliate Rule

2004 2005 2006 Segment profit $525-575 $525-575 $525-575 Annual DD&A * $275-285 $280-290 $290-300 Capital spending Expansion: $30-40 $15-30 $25-40 Non-Exp: $240-250 $265-280 $165-180 Replacement: $25-50 $100-120 $240-260 Total $295-340 $380-430 $430-480 Dollars in millions Gas Pipeline 2004-2006 Guidance * Legal entity basis

Gas Pipeline Challenges and Opportunities Challenge Restore/replace Northwest's 26" pipeline Opportunities Transco rate upside Gulfstream capacity Organic growth over long-term

Midstream Alan Armstrong, Senior VP

Straddle Plants Fort McMurray (Oil Sands) Conway Olefins Fractionator Wyoming Produce over 50% of NGL's coming out of Wyoming San Juan Gather approximately 38% of the gas, ranking Midstream #1 in the basin Gulf Coast Gather 40% of the gas produced in the Western Gulf of Mexico Venezuela Gas injections allow PDVSA to freely produce approximately 700,000 BOPD, which is roughly 50% of all crude oil production

Midstream Segment Profit Segment Profit $46 $(27) $286 $183 Includes: Impairments 42 115 60 123 Gains on sale of assets (16) - (27) - Early retirement/realignment - - - 3 Recurring Segment Profit $72 $88 $319 $309 Operation of Assets sold/To be sold 5 11 9 55 $67 $77 $310 $254 4Q 2002 vs. 4Q 2003 Weaker olefins margins 2002 vs. 2003 Increased Deepwater revenues 4th Quarter 2003 2002 2003 2002 Dollars in millions

Strong operating cash flow Deepwater expansions Gunnison pipeline in-service Devils Tower spar topsides set Asset sales progress NGL Trading & Wholesale Propane - closed 12/03 Wilprise equity ownership - closed 10/03 Tristates equity ownership - closed 10/03 Dry Trail - closed 12/03 Satisfactorily re-contracted ethane in Western Canada Completed 415 well connect program Strong operational metrics Midstream 4Q 2003 Accomplishments

Midstream Remaining Assets for Sale Cameron Meadows/Black Marlin 2Q04 Gulf Liquids (Disc. Operations) 2Q04 Ethylene Distribution 2Q04 Canadian Straddle Plants 3Q04 Conway 3Q04 South Texas 4Q04 Pre-tax Proceeds $500 - 600 Timing of Closing Dollars in millions

2003FC 2003 2004 2005 2006 2-20-03 Segment profit $200-300 $286 $275-375 $300-400 $350-450 Annual DD&A* $190-200 $199 $180-190 $170-180 $175-185 Capital spending $250 $263 $90-110 $60-80 $50-70 CFFO $300-350 $413 Key Assumptions for Ranges: NGL Margins Olefins Margins Deepwater Growth Asset Sales Dollars in millions Midstream 2004 - 2006 Guidance * 2004-2006 on legal entity basis

2002 2003 2004 2005 2006 G&P 263 315 280-330 320-370 350-420 Segment Profit 263 333 280-330 320-370 350-420 Gains/Losses/Impairments - (18) - - - Petchem Services (87) (28) (20)-30 (20)-30 (20)-30 Segment Profit (10) (28) (20)-30 (20)-30 (20)-30 Gains/Losses/Impairments (77) - - - - Assets Sold/To Be Sold 7 (1) 0-20 - - Segment Profit 53 14 0-20 - - Gains/Losses/Impairments (46) (15) - - - Total Segment Profit $183 $286 $275-375 $300-400 $350-450 Segment Profit plus DD&A $364 $485 $455-565 $470-580 $525-635 Dollars in millions Midstream Segment Profit Breakdown-Guidance Note: Sum of ranges for each business line does not necessarily match total range for Midstream segment

Midstream Net Revenue* Components End of Year 2003 2006 * Net Revenue is total revenues before eliminations less cost of goods sold for NGLs, Olefins, Condensate, & Trading Gathering, Compression & Treating Fees Fee Proc. Storage & Trans. Fee Other Revenue Commodity Based Current 0.53 0.14 0.06 0.06 0.21 Gathering, Compression & Treating Fees Fee Proc. Storage & Trans. Fee Other Revenue Commodity Based** Future 0.66 0.09 0.05 0.03 0.17 ** Reflects 2003 margins

$ Millions 2002 2003 2004 2005 2006 Actual / Contracted Business 38.4 98.9 144.1 175.1 157.6 Identified Business 82 Midstream Projected Deepwater Growth East Breaks Placed in service 4th Qtr. 2001 Original Projection for 2003 = 172MMcfd 2003 Actual = 343 MMcfd Canyon Station Production exceeding estimates by 30+ MMcfd Green Canyon Inception to date production is 15% above original projection Devils Tower Spar on location 2Q 2004 start-up Substantial developments in area Gunnison 4th Qtr. In-service 2nd 2004 flow = 23 MBPD 2005 flow = 35 MBPD Segment Profit Before DD&A

Midstream Challenges / Opportunities Challenges Commodity margins Deepwater - contract identified business in 2006 FERC affiliate ruling Opportunities Commodity margins Additional Deepwater prospects Olefins Margins

Midstream Summary 2003 strong financial performance Strategy intact Maintaining focus on core business in spite of asset sales Success in past, present and future Reducing volatility Exciting growth opportunities continue to exist Deepwater Core basins

Power Bill Hobbs, Senior VP

Power 4Q 2003 Segment Profit Accrual Earnings (Losses) ($67) $1 ($268) $11 MTM Earnings (Losses)1 73 126 393 (420) Interest Rate Earnings (Losses) 14 (6) (12) 91 SG&A (17) (29) (124) (209) Operating Expenses & Other Inc (Exp) (35) (17) (79) (49) Impairments (89) (98) (89) (253) Gain on Sale of Assets - - 208 - Origination - - - 204 Income Related to Prior Periods2 - - 105 - Segment Profit/(Loss) ($121) ($23) $134 ($625) 4Q03 4Q02 2003 2002 1 "MTM Earnings (Losses)" reflects realized and unrealized gains/losses on derivative contracts. Note that change in the fair value of underlying non-derivatives are not included in Segment Profit. 2 Amount represents correction made to prior period accounting treatment of certain derivative contracts. In addition to the $81 million in revenues disclosed in the second quarter of 2003, approximately $24 million in related revenues were also recognized in 2003 prior to the correction. Dollars in millions 4th Quarter Dollars in Millions 2003 2002 2003 2002

4th Quarter 2003 2002 2003 2002 Power Segment Profit/(Loss) ($121) ($23) $134 ($625) Includes Impairments 89 98 89 259 Reduction in Force Costs - 6 12 13 Income Related to Prior Periods1 - - (105) - Contract Sales/Liquidations 2 - - (208) - Cal. Refund & Other Accrual Adj. 33 - 33 - Regulatory & Other Loss Accruals - - 20 - Recurring Segment Profit/(Loss) $1 $81 ($25) ($353) Dollars in millions 1Amount represents correction made to prior period accounting treatment of certain derivative contracts. In addition to the $81 million in revenues disclosed in the second quarter of 2003, approximately $24 million in related revenues were also recognized in 2003 prior to the correction. 2 Includes non-derivatives only.

Power Undiscounted Cash Flows-Guidance Tolling Demand Payment Obligations ($393) ($391) ($395) ($400) Resale of Tolling 123 143 117 104 Full Requirements 19 16 41 46 Long Term Physical Forward Power Sales 75 97 100 76 OTC Hedges 6 168 52 78 Estimated Hedges Tolling Revenues 51 108 196 251 ($119) $141 $111 $155 Estimated Merchant Revenue Unhedged $0 $6 $49 $73 Estimated Combined Power Portfolio Cash Flows ($119) $147 $160 $228 Forecasted SG&A Direct (105) (50) (50) (50) Allocated (19) (25) (25) (25) Estimated Cash Flows after SG&A ($243) $72 $85 $153 4Q03 4Q02 2003 2002 Dollars in millions Combined Power Portfolio Estimated as of 12/31/03 Dollars in Millions 2003 2004 2005 2006 Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown.

Power Other Bus. Only W/C Total Portfolio Cash Flow ($243) - ($243) Unusual Items Jackson Sale 188 - 188 Allegheny Termination 100 - 100 Deferred Tax Change 220 - 220 Working Capital and Other 231 (337) (106) Cash Flows from Operations $496 ($337) $159 Dollars in millions Power 2003 Cash Flow

2004 2005 2006 Segment Profit $0-150 $50-150 $50-200 Cash Flows from Operations1 $150-350 $50-150 $50-200 1 Power only, excludes all commodity Margin Volatility Note: Because Power does not currently qualify for Hedge Accounting, actual segment profit may vary significantly from given ranges. Future liquidations, sales or partial sale of the portfolio may result in gains or losses significantly different than ranges given above. Dollars in millions Power 2004-2006 Guidance

Power Challenges / Opportunities Challenges Depressed cycle Stated intent to exit the business Opportunities Higher spark spreads New risk reducing, value enhancing origination deals Increased liquidity resulting in additional forward hedging Improved credit resulting in reduced prepays for gas Favorable resolution of ongoing litigation and investigations

Power Outlook Power markets depressed West has positive exit value Negative exit value for remainder Estimated cash flows from hedges cover approximately 98% of demand payment obligations through 2010 Expect positive cash flows despite depressed markets through 2010 Opportunities and risks greater after 2010 Impairments of goodwill and Hazelton plant Net book value of portfolio & other long-lived assets in excess of $800 million Other net assets (A/R, Margin, etc) total approximately $400 million Tolling, full requirements, storage, transportation and transmission contracts represent additional exposure not reflected on balance sheet

2004-2006 Consolidated Outlook Don Chappel

Consolidated 2004 Segment Profit Guidance 275 - 375 Midstream 25 - (40) Other/Rounding 275 - 340 Exploration & Production Dollars in millions $525 - 575 Gas Pipeline $1,100 - 1,250 2004 Forecast 0 - 150 Power $1,100 - 1,400 Total

1,600 - 2,000 1,000 - 1,300 $1,100 - $1,400 0 - 200 Net Income Cash Flow from Operations 20 - 200 Income from continuing operations Segment profit* $ Dollars in millions, except per-share amounts $0.00 - $0.40 EBITDA Diluted Earnings Per Share Consolidated 2004 Guidance Note: Excludes potential gains, losses and impairments

2004 Forecast EBITDA Reconciliation 650 - 700 DD&A 60 - 5 Other/Rounding 810 - 900 Net Interest Dollars in millions $0 - 200 Net Income $1,600 - 2,000 EBITDA 0 - 20 Income from Disc. Operations 80 - 175 Provision for Income Taxes

Gas Pipes E&P Midstream Power Corp/Other Total 275 - 340 160 - 180 435 - 520 275 - 375 180 - 190 455 - 565 25 - (40) 15 - 20 40 - (20) 0 - 150 20 - 25 20 - 175 1,100 - 1,400 650 - 700 1,750 - 2,100 (130) - (110) 0 - 50 (20) - (40) 1,600 - 2,000 525 - 575 275 - 285 800 - 860 Segment Profit (Loss) DD&A* Segment Profit before DDA General Corporate Expense Investing Income Other/Rounding TOTAL Consolidated 2004 Forecast Segment Contribution * Legal entity basis

Consolidated 2004 - 2006 Outlook 900 - 1,100 900 - 1,100 700 - 800 Capital Expenditures 700 - 800 650 - 750 650 - 700 DD&A 2006 2005 2004 Dollars in millions 1,100 - 1,400 Segment Profit 39% 39% 39% 1,400 - 1,700 1,300 - 1,600 1,000 - 1,300 Cash flow from Operations 1,400 - 1,700 1,300 - 1,600 Effective Tax Rate* * An additional $25 million income tax expense is forecast each year

Consolidated Drivers Dollars in millions

Maintain a cash/liquidity cushion of $1.0 billion plus Complete new bank credit facilities Continue to de-lever - striving for investment grade ratios Uses of excess cash Pay scheduled debt retirements Early debt reduction Disciplined EVA(r) -based investment Consider dividend and/or share repurchase policy upon achieving investment grade Financial Strategy

Summary Steve Malcolm

Strategy Commercial Natural gas assets in key growth markets where we enjoy the competitive advantages of scale, low- cost position and market leadership Financial Create and maintain adequate liquidity from all available sources to fully support business strategy De-leverage through combination of asset sales, refinancing, cost-cutting Develop balance sheet capable of supporting and ultimately growing business and value

Exploration & Production Generates free cash flow, primary growth driver Midstream Generates free cash flow, decreasing volatility, growth in Deepwater Gas Pipeline Generates free cash flow, steady contributor Power Exit business Reduce risk and volatility Business Unit Positioning

Initiate & Stabilize Execute Restructuring Emerge Avoid bankruptcy Address liquidity crisis Restore customer and supplier confidence Complete asset sales Rationalize cost structure Manage liquidity De-lever Restore confidence of and gain access to capital markets Position company for integrated natural gas growth Optimize capital structure Capitalize on strategic position Measures of Success A Work in Progress

Appendix A-1

Appendix Contents Exploration & Production Arkoma Basin Average Well Economics A-4 San Juan Basin Average Well Economics A-5 Powder River Basin Average Well Economics A-6 Piceance Basin Average Well Economics A-7 Gas Pipeline Northwest 2003 Expansion Projects A-8 Transco 2003/04 Expansion Projects A-9 Gulfstream 2004 Expansion Project A-10 Northwest Rate Comparison A-11 Transco Rate Comparison A-12 Contract Expirations A-13 Northwest Customer Base A-14 Transco Customer Base A-15 Gulfstream Customer Base A-16 Northwest Supply Diversity A-17 Page A-2

Appendix Contents (cont.) Midstream Operational Metrics-Daily Gathering Volume A-18 Operational Metrics-NGL Production/Spread vs. Margin A-19 Power Physical Natural Gas A-20 Total Undiscounted Cash Flows A-21 West Undiscounted Cash Flows A-22 Mid. Cont. Undiscounted Cash Flows A-23 East Undiscounted Cash Flows A-24 Consolidated Scheduled Debt Maturities A-25 Page A-3

20+ years Gross Reserves 848 MMcf 450 Mcfd Mcfd Average 2004 Lona Valley Well Exploration & Production Arkoma Basin A-4

Gross Reserves 1.52 Bcf 18 years Mcfd 700 Mcfd Average 2004 Fruitland Coal Well Exploration & Production San Juan Basin A-5

Average 2004 Big George Coal Well Exploration & Production Powder River Basin A-6 6-8 years 430 40 430 24 Months Mcfd Dewatering Process 0 12 400 Gross Reserves 0.49 Bcf

Average 2004 Mesaverde Well Exploration & Production Piceance Basin A-7 1561 Mcfd EUR = 1.6 BCF Gross Reserves 1.34 Bcf 20+ years Mcfd

Gas Pipeline Northwest 2003 Expansion Projects Rockies 175 MDth/d Nov 2003 $124 MM Evergreen 276 MDth/d Oct 2003 $198 MM Columbia Gorge 57 MDth/d Nov 2003 $43 MM A-8

Gas Pipeline Transco 2003/2004 Expansion Projects Trenton Woodbury 51 MDth/d Nov 2003 $20 MM Momentum 323 MDth/d 2003/2004 $175 MM A-9

Gas Pipeline Gulfstream 2004 Extension Project FPL's Manatee Plant FPL's Martin Plant Total Capacity 1.1 Bcf/d A-10

Demand Commodity GTN Third Party Fuel Northwest / Piaute 0.2701 0.037 0.3094 0.188 GTN / Tuscarora 0.254 0.008 0.4833 0.186 Northwest 0.2701 0.037 0 0.073 GTN 0.069 0.001 0 0.017 Northwest 0.2701 0.037 0 0.073 GTN 1.11 0.01 0 0.093 Reno, NV Medford, OR Spokane, WA Gas Pipeline Northwest Rate Comparison 100% LF Rate Comparison System gas prices are as follows: Northwest Blended - $4.61 GTN - $4.57 A-11

Demand Commodity Fuel Other Transco 0.2369 0.009 0.117 0.0137 SNG 0.3547 0.029 0.1449 0.012 Transco 0.3344 0.0148 0.1957 0.0137 SNG 0.3547 0.029 0.1449 0.012 CGT 0.3939 0.0291 0.2973 0.0026 Transco 0.3935 0.018 0.2409 0.0137 Iroquois 0.4162 0.0054 0.0644 0.0008 CGT 0.3939 0.0291 0.2973 0.0026 Tenn 0.4156 0.1126 0.4045 - TETCO 0.4961 0.0764 0.6012 - Zone 4 Zone 5 Zone 6 $0.376 $.541 $0.558 $0.541 $0.722 $0.666 $0.486 $0.722 $0.932 $1.173 System gas prices are as follows: Transco - $5.091 Southern Natural - $5.427 Columbia - $5.498 Iroquois - $6.375 Tennessee - $5.382 Texas Eastern - $5.435 Gas Pipeline Transco Rate Comparison 100% LF Rate Comparison A-12

Gas Pipeline Contract Expirations - Cumulative 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Northwest 9.2 349.1 109.1 496.2 160 58.4 102 379.6 Transco 311.874 370.08 1200.474 590.133 111.115 175.527 477.796 700.187 222.104 635.281 Northwest Capacity 2247.8 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 Transco Capacity 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 Transco Contract Expiration % 0.11 0.16 0.33 0.41 0.43 0.45 0.52 0.62 0.65 0.74 Transco Cumulative Expirations 744.272 1114.35 2314.83 2904.96 3016.07 3191.6 3669.4 4369.58 4591.69 5226.97 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Northwest 21.8 94.3 475.2 496.5 79.4 102 379.6 Transco 311.874 370.08 1200.474 590.133 111.115 175.527 477.796 700.187 222.104 635.281 Northwest Capacity 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 2509.7 Northwest Cumulative Expirations 0 0 21.8 21.8 116.1 591.3 1087.8 1167.2 1269.2 1648.8 Transco Capacity 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 7053.7 Transco w/ evergreen 744.272 370.08 1200.474 590.133 111.115 175.527 477.796 700.187 222.104 635.281 1 1 1 1 1 1 1 1 1 1 Northwest Contract Expiration % 0 0 0.01 0.01 0.05 0.24 0.43 0.47 0.51 0.66 Northwest's average contract life is 8.7 years Transco's average contract life is 5.8 years A-13

Gas Pipeline Northwest Customer Base A-14

Gas Pipeline Transco Customer Base A-15 Local Distribution Co. 22 Baa2/BBB+ South Jersey Gas Company Local Distribution Co. 30 Baa2 Philadelphia Gas Works Local Distribution Co. 21 A3/A- Atlanta Gas Light Local Distribution Co. 46 A3/A SCANA Local Distribution Co. 51 A1/A ConEd of NY Local Distribution Co. 74 A3/A Piedmont Natural Gas Co. AA-/A2 B3/B+ A3 Baa1/BBB Credit Rating Local Distribution Co. 86 Keyspan Gas East Local Distribution Co. 21 Washington Gas Light Co. Local Distribution Co. $115 PSEG Energy Resources Marketer 34 Williams EM&T Customer Type 2003 Revenue ($MM) Company

Gas Pipeline Gulfstream Customer Base Contract terms are for 18 - 23 years Muni. Utility A3 $2.0 10 FMPA 350 68 35 10 190 30 32 FT Contract Mdth/d $70.3 $13.7 $7.0 $2.0 $38.0 $6.0 $6.4 Demand Revenue ($MM) PHASE II (Dec 2004) PHASE I (May 2002) IOU BBB/A1 FPL IPP CCC+/Caa1 Calpine LDC BBB+ Central FL Gas IOU AAA/A1 Lakeland LDC BBB-/Baa2 Peoples Gas IOU A Seminole IOU BBB/A2 FPC Primary Company Type Rating Company Note: Revenue is an estimated first full year using the negotiated rates. A-16

Gas Pipeline Northwest Supply Diversity A-17

Midstream 2003 Strong Operational Metrics A-18 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 Gathering Volumes 5665 5643 5971 5729 6104 6072 6092 5982

Midstream 2003 Strong Operational Metrics Frac Spread vs. Net Liquid Margin Total NGL Production A-19 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 U.S. 149 135 151 150 147 119 138 132 Canada 144 145 162 155 153 123 132 150 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 HH/MB Frac Spread 10.24 9.7 13.09 11.77 7.68 1.93 8.34 12.19 NLM 5.32 7.51 11.76 13.05 17.95 7.98 6.33 10.81

Power Physical Natural Gas Average annual requirements 2.7 Bcf/d with peak of 3.5 Bcf/d 48% for Power 20% power-plant supply 28% third-party transactions 52% for Williams' core businesses Transportation 2.5 Bcf/d 35% for Power 65% for Williams' core businesses Storage 21 Bcf 67% for Power 33% for Williams' core businesses Improving market liquidity and credit A-20

Power Total Undiscounted Cash Flows A-21 ($ Millions)

Power West Undiscounted Cash Flows A-22 ($ Millions)

Power Mid. Cont. Undiscounted Cash Flows A-23 ($ Millions)

Power East Undiscounted Cash Flows A-24 ($ Millions)

Consolidated Scheduled Debt Maturities 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013-2020 2021-2022 2023-2026 2027-2030 2031 2032 2033 Misc. Notes 285 247 972 920 385 138 1014 1078 1000 757 751 262 100 1170 850 300 9.25% Notes 679 PACS 1100 ($ Millions) A-25