Exhibit 99.1

Williams Analyst Conference Call 2nd Quarter 2004 August 5, 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.

2Q04 Review Steve Malcolm, Chairman, President & CEO

Headlines Williams delivers on restructuring Balance sheet gets stronger Adequate liquidity continues Debt reduction ramps up; new tender announced today Asset sale program ending Credit-rating agencies take notice Western power issues go away; utilities pay their bill IBM deal helps to lock in G&A cost reductions Power - no exit to date; cash flow positive year-to-date

Headlines Williams delivers solid 2Q performance Recurring results see big improvement Gas Pipeline steady Midstream gets boost from new deepwater expansions and strong olefins; increases guidance E&P increases production but lowers 2004 earnings guidance as Costs increase Hedges limit upside Power in-line with our expectations; mark-to-market gains offset seasonally soft quarter and legacy position impacts

Headlines Williams poised for post-restructuring growth, value-creation Natural gas businesses provide organic growth opportunities Investments today preserve, enhance competitive position Drilling activity, production levels both increase Deepwater Gulf infrastructure prime for incremental business Seriously considering MLP for certain Midstream assets and future acquisitions Gulfstream expansion gets under way Scale and scope of investments ramp up as restructuring finish line nears Value creation Growth Financial discipline

Midstream Complete deepwater projects Complete asset sales Maintain competitive position - MLP? Capture our share of new deepwater production 2004 2005 2006 2007 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES The Road Ahead Complete announced expansion projects Northwest testing and return to service Northwest capacity replacement Rate cases Expansions Piceance major growth vehicle Powder River permits and dewatering Arkoma production doubles Early debt retirement New credit facilities Cost reductions Support growth Investment-grade ratios if exit Power Examine dividend level Spark spreads improve Risk Reduction Solid Financial Footing Disciplined Growth Powder River grows Exit or optimize If no exit, continue to reduce risk, generate cash, meet commitments Piceance growth continues MLP?

Financial Results & 2004 Outlook Don Chappel, CFO

2nd Quarter YTD 2004 2003 2004 2003 Income (Loss) from Continuing Ops.* ($18) $114 ($19) $70 Income (Loss) from Discont. Ops. - 156 11 146 Effect of Accounting Change - - - (761) Net Income/(Loss)* ($18) $270 ($8) ($545) Net Income/(Loss) Share* ($0.03) $0.46 ($0.02) ($1.10) Recurring. Inc./(Loss) from Cont. Ops Avail to Common Shareholders** $64 ($12) $67 ($55) Rcr. Inc./(Loss) from Cont. Ops /Share** $0.12 ($0.02) $0.13 ($0.10) Financial Results * Includes gains on asset sales, impairments, prior period corrections, restatements for discontinued operations and the reclassification of results related to the transfer of certain regulated gathering assets from Midstream to Gas Pipelines (see Notes 1 & 2 of the current 10-Q). ** A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts)

2004 2003 2004 2003 Income/(Loss) from Cont. Ops. ($18) $114 ($19) $70 Gains on Sale of Assets - (274) - (274) Impairments/Losses/Write-offs 24 137 24 149 Income (Expense) Related to Prior Periods 11 (93) 11 (107) Debt Retirement Expenses 97 - 97 - Other 1 18 8 31 Less: Income Tax Provision 51 (109) 54 (105) Recurring Income from Cont. Ops. $64 $11 $67 ($26) Preferred Dividend - (23) - (29) Rec. Inc./(Loss) from Cont. Ops. Avail. to Com. $64 ($12) $67 ($55) Recurring Income/(Loss) from Cont. Ops/Share $0.12 ($0.02) $0.13 ($0.10) Recurring Income from Cont. Operations Dollars in millions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD

2004 2003 2004 2003 Segment Profit $305 $636 $571 $880 Net Interest Expense (222) (395) (461) (736) Debt Retirement Expense (97) - (97) - Other Income (Expense) - Net (21) (1) (38) 40 Income/(Loss) from Cont. Ops. Before Tax* (35) 240 (25) 184 Provision (Benefit) for Income Tax (17) 126 (6) 114 Income/(Loss) from Continuing Ops.* ($18) $114 ($19) $70 Income from Discontinued Ops. - 156 11 146 Effect of Accounting Change - - - (761) Net Income/(Loss)* ($18) $270 ($8) ($545) Net Income Components * Income/(Loss) from Continuing Operations includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Note 2 of the current 10Q). Dollars in millions (except per share amounts) 2nd Quarter YTD

Second Quarter Segment Profit Reported Recurring 2Q04 2Q03 2Q04 2Q03 Gas Pipeline $133 $116 $142 $142 Exploration & Production(1) 43 179 55 87 Midstream Gas & Liquids 99 45 99 54 $275 $340 $296 $283 Power(2) 45 348 45 93 Other (15) (52) (5) (2) Segment Profit(3) $305 $636 $336 $374 Dollars in millions (1) E&P 2Q04 reported results include $11 million loss provision related to prior periods. (2) Power 2Q03 reported results include $93 million income for prior period item correction (3) Reported segment profit Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Note 2 of the current 10Q). A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation.

YTD Segment Profit Reported Recurring 2004 2003 2004 2003 Gas Pipeline $280 $266 $289 $292 Exploration & Production(1) 95 293 106 201 Midstream Gas & Liquids 207 157 207 166 $582 $716 $602 $659 Power(2) 12 212 12 (45) Other (23) (48) (5) 3 Segment Profit(3) $571 $880 $609 $617 Dollars in millions (1) E&P 2Q04 reported results include $11 million loss provision related to prior periods. (2) Power 2003 reported results include $107 million income for prior period item correction (3) Reported segment profit Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Note 2 of the current 10Q). A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation.

Recurring Segment Profit 2Q2003 $374 Power (49) - Lower gross margin incl. MTM -$63 million - Reduced SG&A expenses +$12 Midstream 45 - New deepwater assets +$13 million - Higher NGL margins +$13 million - Improved olefins results +17 million Gas Pipeline 0 - New projects added +$13 million - Increased expenses and property taxes -$4 million - Lower short term firm revenues and credits -$10 million Exploration & Production (32) - Lower net realized price & 2003 MTM gain -$18 million - Loss of excess firm transport & asset sales -$14 million - Higher operating costs -$7 million - Higher volumes in 2Q04 +$7 million Other (3) Recurring Segment Profit 2Q2004 $336 Major Changes in Recurring Segment Profit Dollars in millions

Beginning Cash @ 12/31/03* $2,318 Cash Flow from Continuing Operations 604 Cash Flow from Discontinued Operations 12 Asset Sales 394 Restricted Investments (LC Collateral) 381 Debt Retirements (2,218) Capital Expenditures/Investments (331) Debt Premiums/Issuance Costs (100) Other-Net (30) Ending Cash @ 6/30/04* $1,030 Change in Cash ($1,288) Restricted Cash (not included above) $176 YTD Cash Information Dollars in millions * Includes cash for discontinued operations of $2.5 million at 12/31/03 and $0 at 6/30/04

Debt Balance Debt Balance @ 12/31/03 * $11,978 7.7% Scheduled Debt Retirements & Amortization (778) Tendered Debt Retirements (1,171) Open Market Purchases (269) Debt Balance @ 6/30/04 $9,760 7.3% Net Decrease in Debt ($2,218) Fixed Rate Debt $9,165 7.6% Variable Rate Debt $595 3.3% Avg. Cost * Debt is long-term debt due within 1 year plus long-term debt plus notes payable; includes FELINE PACS Dollars in millions

Consolidated 2004 Segment Profit Guidance Dollars in millions 2004 Forecast * Midstream excludes Canadian assets sold and reclassified as discontinued operations ** Restated to remove Canadian assets sold and reclassified as discontinued operations *** Power guidance assumes zero 2nd half 2004 mark-to-market gains / (losses) Gas Pipeline $540 - 570 Exploration & Production 235 - 260 Midstream* 325 - 375 Other/Rounding 0 - 45 $1,100 - 1,250 Power*** 0 - 150 Total $1,100 - 1,400 275 - 300 275 - 360 ** 0 - (10) $1,075 - 1,375 ** $1,075 - 1,225 ** $525 - 575

Segment profit $1,100 - $1,400 $1,075 - $1,375 Net Interest Expense (820) - (860) Early Debt Retirement Costs (250) - (200) (225) - (175) Other (Primarily General Corporate Costs) (80) - (125) Pretax Income (Loss) ($50) - $215 Provision (Benefit) for Income Tax 5 - (125) 5 - (105) Income / (Loss) from Continuing Ops (45) - 90 Income from Discontinued Ops * 160 - 185 Net Income (Loss) - Reported $115 - $275 Diluted EPS - Reported $0.22 - $0.52 Net Income - Recurring ** $107 - $212 Diluted EPS - Recurring ** $0.20 - $0.40 Dollars in millions, except per-share amounts Consolidated 2004 Forecast Guidance * Includes gain on sale of Canadian straddle plants ** Excludes early debt retirement costs, gains and losses on assets sales and impairments *** Previous guidance restated for Canadian asset sale and reclassification to discontinued operations (840) - (880) ($70) - $195 ($65) - $90 0 - 20 ($65) - $110 ($0.12) - $0.21 $75 - $195 $0.14 - $0.37 Previous*** same Current

2004 Forecast EBITDA Reconciliation Dollars in millions Net Income $115 - $275 Income from Disc. Operations (160) - (185) Net Interest 820 - 860 DD&A 650 - 700 Provision (Benefit) for Income Taxes (5) - 125 Other/Rounding (70) - 25 EBITDA - Reported $1,350 - $1,800 Early Debt Retirement Fees 250 - 200 EBITDA - Recurring $1,600 - $2,000

MLP Direction Positives Acquisition currency Retain control of assets Additional access to capital markets Added visibility for Midstream business unit valuation Considerations Complicated tax / governance / reporting structure Hurdles due to current financial agreements Ratings agencies neutral to negative view Current direction Seriously considering establishment of MLP Initial assets may include some of remaining assets for sale, e.g. Conway Flexibility for expansion through acquisition or drop-down transaction Expected IPO timing likely 1Q or 2Q 2005

MLP Initial Scale Considerations Starting small Maximum flexibility to make acquisitions and drop-down acquisitions Growth more sustainable starting from a smaller base As GP, Williams incentive distributions increase geometrically as distributable cash flow grows Asset considerations Not all Midstream assets are appropriate Targeting more mature assets Rating agency considerations Small size would mitigate concerns of ratings agencies Covenants Certain covenants would initially limit assets which could be an MLP Some midstream assets are pledged as collateral

Business Unit Results

Exploration & Production Ralph Hill, Senior Vice President

2nd Quarter YTD 2004 2003 2004 2003 Exploration & Production Segment Profit Dollars in millions Segment Profit $43 $179 $95 $293 Non recurring: Ownership issue 11 - 11 - Gain on sale of assets - (92) - (92) Recurring Segment Profit $55* $87 $106 $201 2Q04 to 2Q03 decrease includes ($18) million primarily due to market to market gain in 2Q03 and lower net realized price ($8) million due to excess transport ($7) million due to higher operating expenses ($6) million due to assets sold in 2Q03 $7 million increase due to higher volumes in 2Q04 $55 million negative hedge impact in second quarter 2004, $101 million year to date Base business sequential quarter improved Sequential volumes increased 11%, recurring profit increased 6% * Does not add due to rounding

1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q '04 Retained Properties 130.6 111.7 101.2 90.3 94 101.1 Sold Properties 9.3 9.3 Exploration & Production Recurring Segment Profit + DD&A

Exploration & Production Second Quarter Accomplishments Significant Production Growth Drilling activities increases Shorter Piceance drilling cycle Additional rigs added in San Juan, Arkoma and Powder River Powder River permitting progress Bolt on acquisitions accomplished: Arkoma San Juan Powder River Piceance Trail Ridge area drilling commences Significant Big George volume growth Expanded Piceance firm takeaway capacity Avg 2002 Avg 2003 Jun 04 Retained Production 460 465 511 International 42 44 44

Piceance Powder River San Juan Arkoma/Other International Jan. '04 166 121 142 28 41 Jun '04 226 119 143 28 43 Dec. '04 268 119 145 30 44 Exploration & Production Current and Projected Volumes Additional volumes due to drilling efficiencies Previous Estimate

Williams Big George Gross Production Increasing 61.6 MMcfd, 603 wells 100 Miles 60 Miles Wyodak Fairway 743.1 MMcfd* CAMPBELL COUNTY Gillette JOHNSON SHERIDAN Big George Fairway 147.5 MMcfd* * WOGCC Data April 2004 Williams Operated Pilots Scale 0 6 miles Partner Operated Pilots Other Industry Pilots Exploration & Production Powder River Basin, WY - Big George and Wyodak Coal Fairways Carr Draw South Prong Schoonover Road S.G. Palo Pleasantville Areas Kingsbury Area All Night Creek Area Bullwhacker Creek

Exploration & Production Piceance Basin Acreage Denver

2004 Previous Guidance $275 - 300 Revisions: 1) Hedge price impact ( 7) 2) Excess transport ( 15) 3) Higher operating expenses ( 11) 4) Gathering fees/other ( 10) 5) Increased volumes 15 ($28) Non-Recurring ($11) Revised Guidance $235 - 260 Dollars in millions Exploration & Production 2004 Segment Profit Guidance Revision

2004 Previous Guidance $325 - 375 Revisions: 1) Increase in overall drilling program costs 13 2) Additional operated wells drilled 27 3) Additional partner operated wells 11 4) Accelerated plant & compression upgrades 21 Revised Guidance $400 - 450 Dollars in millions Exploration & Production 2004 Capital Guidance Revision Additional growth capital $59 million

Exploration & Production 2004-2006 Guidance Note: If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below. Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes 2004 2005 2006 Segment profit $235 - 260 $375 - 475 $425 - 525 Annual DD&A $160 - 180 $195 - 225 $230 - 260 Capital spending $400 - 450 $400 - 450 $450 - 500 Production (MMcfe/d) 525 - 550 600 - 700 700 - 800 Hedged Volume (MMcfe/d) 418 286 298 Hedged Price (NYMEX) $4.04 $4.44 $4.39 Dollars in millions $325 - 375 $275 - 300

Delivering on our volume growth Stepping up development drilling activity Decreasing 2004 segment profit guidance due to "boom" costs and hedged prices Plan based on organic growth from existing positions Investments are short time cycle, fast cash returns High-quality reserve base History of high success, low finding costs Diverse producing basins, long-term drilling inventory Significant probables and possibles inventory Experienced and talented work force Exploration & Production Key Points

Midstream Alan Armstrong, Senior Vice President

Segment Profit $99 $45 $207 $157 Aux Sable Impairment - 9 - 9 Recurring Segment Profit $99 $54 $207 $166 Dollars in millions Midstream Segment Profit 2Q04 vs. 2Q03 Impact New Deepwater Assets $ +13 Higher NGL Margins +13 Improved Olefins results +17 2nd Quarter YTD 2004 2003 2004 2003

Midstream Second Quarter Accomplishments First production on Devils Tower Canadian straddles sale Favorable Gulf Liquids arbitration award Secured Front Runner dedication Federal court remands FERC ruling * Excludes gains/losses/impairments 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2003 151 93 109 106 2004 151 144 Recurring Segment Profit + Depreciation*

Midstream targeted $500 - 600 MM Canadian straddles yield $536 million cash + $30 million of L.C. capacity South Texas regulated assets - $28 million Yields nearly $600 million Gulf Liquids pending Ethylene distribution system and storage system pending NGL storage assets held back for MLP Midstream Asset Sale Update

Midstream MLP Discussion Points Provides acquisition vehicle for additional scale in Midstream Maintains our competitive advantage in core basins Allows continuing presence in NGL services sector Allows Williams to retain control of assets No negative impact to current earnings guidance

Midstream 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit $325-375 $300-400 $350-450 Annual DD&A $170-180 $175-185 $175-185 Capital Spending $90-110 $60-80 $50-70 $275-360 Note: - Both current & previous guidance excludes results & gains associated with Canada straddle plants that are now included in Discontinued Operations. - If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below Discontinued Ops. Adjustment - Canadian Straddle Plants Segment Profit $25 - - Annual DD&A $10 - -

Midstream Key Points Continued strong demand for services in core areas 2Q 2004 performance yields second consecutive increase in guidance Asset sales goals accomplished Deepwater projects adding significant operating profit Reliable operational performance attracting growth around existing assets MLP would benefit Midstream's scale focused strategy

Gas Pipeline Doug Whisenant, Senior Vice President

Gas Pipeline Segment Profit 2nd Quarter YTD 2004 2003 2004 2003 Segment profit $133 $116 $280 $266 Includes: Write-off software project - 26 - 26 Write-off of previously capitalized cost for idled segment 9 - 9 - Recurring Segment Profit $142 $142 $289 $292 2Q04 vs. 2Q03 Incremental projects, $14 million Offset by: Lower transportation revenue, $5 million Higher operating taxes, $4 million Gas cost credit in 2003, $2 million Lower environmental credit sales, $3 million Dollars in millions

Gas Pipeline Second Quarter Accomplishments Began construction of Gulfstream Phase II Assumed operations of Transco production area facilities Began construction of Everett Delta Lateral Partial (131 MDtd) return to service of 26-inch Successful Leidy to Long Island open season 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2003 209.1 202.5 203.2 213.8 2004 207.8 203

2004 2005 2006 Segment profit $540 - 570* $525 - 575 $525 - 575 Annual DD&A $270 - 280 $280 - 290 $290 - 300 Capital spending $280 - 320 $350 - 400 $450 - 520 Dollars in millions Gas Pipeline 2004-2006 Guidance $335 - 380 $430 - 490 $295 - 340 $525-575 $275-285 * Includes $9 million non-recurring charge in 2Q '04

Gas Pipeline 2004-2006 Capital Spending Detail $450 - 520 $350 - 400 $280 - 320 Total 20 - 30 20 - 30 35 - 45 260 - 300 45 - 55 35 - 45 70 - 75 $140 - 150 $195 - 215 $140 - 155 Normal Maintenance 2006 2005 2004 Dollars in millions $430 - 490 40 - 50 $335 - 380 Clean Air Act NWP 26" Restore/Replace Expansion 90 - 100 30 - 40 60 - 75 15 - 25 25 - 35 240 - 275 $150 - 160 $155 - 165 75 - 85 $295 - 340 105 - 115 25 - 30 30 - 45 Note: Amounts include AFUDC If guidance has changed, previous guidance from 5/06/04 is shown in italics directly below

Gas Pipeline Northwest 26-inch Restore-to-Service Completed restoration phase Restored 111 miles of 26-inch mainline Represents 131Mdth/d of idled 360 Mdth/d capacity In-service June 22

Gas Pipeline Northwest 26-inch Capacity Replacement Replace 360 MDth/d of capacity Approximately 80 miles of 36" loop; 12,000 hp of compression November 2006 in-service Incorporates 13 MDth/d of capacity relinquished in Reverse Open Season Environmental and permitting work underway Projected cost $310-360 million Rate Case planned effective January 2007 to recover costs

Gas Pipeline Transco Leidy to Long Island Expansion 100 MDtd fully subscribed expansion from the Leidy Hub to Long Island, NY Capital investment ? $150 million Projected in-service date, Nov 2007 Leidy Hub PA NY MD NJ Long Island

Gas Pipeline Gulfstream Update Phase II construction underway 109-mile, 30" extension to serve Florida Power & Light's Martin plant 350 Mdth/d, long-term commitment by FPL December 2004 in-service Capacity under long-term contract Today: 305 Mdth/d (28% of capacity) Mid-2005: 705 Mdth/d (64% of capacity) Phase II project economics Total cost $250 million; project financed Long-term project financing in 2005

26-inch Return-to-Service complete (June 22) 26-inch Capacity Replacement, 11/06 targeted ISD Expansion projects Central New Jersey Leidy to Long Island Gulfstream Phase II Rate cases effective in 2007 NWP TGPL Gas Pipeline Key Points

Power Bill Hobbs, Senior Vice President

2nd Quarter YTD 2004 2003 2004 2003 Power Segment Profit Dollars in millions Gross Margin $72 $228 $71 $138 SG&A (20) (44) (36) (81) Op. Exp. & Other Inc / (Exp) (7) 164 (23) 155 Reported Segment Profit $45 $348 $12 $212 Includes: Regulatory Settlement - 20 - 20 Prior period correction* - (93) - (107) Gains on sale of assets/contracts - (182) - (182) Reduction in force costs - - - 12 Recurring Segment Profit $45 $93 $12 ($45) * 2003 amounts reflect corrections as disclosed in 2003 10-K

Portfolio cash flows consistent with forecast in Power Tutorial Portfolio volumes up more than 70% Portfolio cash flow up more than $60 million Held Power tutorial on June 17 Western power issues resolved February 25 settlement with three California utilities FERC approved settlement on July 2 Williams has received approximately $104 million related to the settlement Power Second Quarter / Recent Accomplishments

Power Undiscounted Cash Flows Variance Analysis 4Q03 4Q02 2003 2002 Dollars in millions Dollars in millions * Forecast included in Power Tutorial held 6/17/04

Power Power Segment CFFO * "Other BU Working Capital" relates to other business units but is managed by the Power Business Unit. Actual Forecast 3Q & 4Q 1Q2004 2Q2004 YTD 2004 2004 2004 Power Portfolio 6 19 25 35-65 60-90 Storage & Legacy 75 (33) 42 (82)-(52) (40)-(10) 81 (14) 67 (47)-13 20-80 Other Working Capital: Power Stand-Alone 82 (75) 7 Power Stand-Alone CFFO 163 (89) 74 (3)-137 130-270 Other BU Working Capital* (76) 202 126 Power Segment CFFO 87 113 200 (50)-150 150-350 Dollars in millions

Segment Profit to Cash Flow Total Segment 2Q04 Dollars in millions

2004 2005 2006 Segment Profit* $0 - 150 $50 - 150 $50 - 200 Capital Expenditures $0 $0 $0 Cash Flows from Operations $150 - 350 $50 - 150 $50 - 200 Dollars in millions Power 2004-2006 Guidance * Assumes 2nd half 2004 MTM gains or losses are zero, however actual results will vary due to MTM results

Power Key Points Expect to generate positive cash flow from operations Significantly hedged cash flow through 2010 Significant natural gas business Merchant upside in West and Northeast Working to reduce risk through forward power sales Operational and environmental obligations very limited Resolving legacy issues Strong commercial and financial capabilities Continue efforts to increase transparency

Financial Overview & 3-Year Outlook Don Chappel

Consolidated 2004 - 2006 Outlook 2006 2005 2004 Dollars in millions Segment Profit DD&A Cash Flow from Ops. Capital Expenditures Effective Tax Rate** Cash Tax Rate $1,100 - 1,400 $650 - 700 $1,000 - 1,300 $775 - 875 39% 3-5% $1,300 - 1,600 $650 - 750 $1,300 - 1,600 $800 - 1,000 39% 3-5% $1,400 - 1,700 $700 - 800 $1,400 -1,700 $900 - 1,100 39% 4-8% $725 - 825 $1,075 - 1,375 * * Restated to remove Canadian assets sold and reclassified as discontinued operations ** An additional $25 million income tax expense is forecast each year Note: If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below

2004 2005 2006 Exploration & Production $400 - 450 $400 - 450 $450 - 500 Midstream 90 - 110 60 - 80 50 - 70 Gas Pipeline 280 - 320 350 - 400 450 - 510 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $775 - 875 $800 - 1,000 $900 - 1,100 Dollars in millions 2004-2006 Capital Exp. By Business Notes: - Sum of ranges for each business line does not necessarily match total range - If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below $325 - 375 $725 - 825 295 - 340 335 - 380 430 - 490

$1.5 billion cash at August 1, 2004 Today commencing cash tender offer and consent solicitation for all $800 million 8 5/8% notes due 2010 Will use available cash and liquidity to fund purchase of notes accepted under the offer Increasing revolving credit facility by $275 million to a total capacity of $1.275 billion and combined credit facilities total $1.8 billion ($1.1 billion available) Total liquidity is not affected by tender offer Achieves year-end goal of reducing debt to ~$9 billion Debt Reduction Action

Cash @ 6/30/04 $1.0 Proceeds from Canada Sale 0.5 Cash Available $1.5 Current Unused Revolver 0.8 Increase in Revolver Capacity 0.3 Total Liquidity $2.6 Liquidity Cushion Required (1.3) Liquidity Available for Tender Offer $1.3 Liquidity Available for Tender Offer Dollars in billions * * Targeted minimum liquidity is $1.0 billion

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 54 247 119 323 640 53 214 1018 998 757 751 292 100 1170 850 300 PACS 1100 Tender Offer 800 Dollars in millions 800

Maintain a cash/liquidity cushion of $1.0 billion plus 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 ratios Combination of growth in operating cash flows and reduction in interest costs drives value creation Drive/enable sustainable growth in EVA(r)/ shareholder value Financial Strategy/Key Points

Summary Steve Malcolm

Midstream Complete deepwater projects Complete asset sales Maintain competitive position - MLP? Capture our share of new deepwater production 2004 2005 2006 2007 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES The Road Ahead Complete announced expansion projects Northwest testing and return to service Northwest capacity replacement Rate cases Expansions Piceance major growth vehicle Powder River permits and dewatering Arkoma production doubles Early debt retirement New credit facilities Cost reductions Support growth Investment-grade ratios if exit Power Examine dividend level Spark spreads improve Risk Reduction Solid Financial Footing Disciplined Growth Powder River grows Exit or optimize If no exit, continue to reduce risk, generate cash, meet commitments Piceance growth continues MLP?

Summary 2nd quarter results solid Debt reductions continue with new tender announced today Asset sales program essentially completed Adequate liquidity continues Growth opportunities identified Significant work outsourced to IBM Seriously considering MLP Continuing efforts to exit Power

Non-GAAP Reconciliations

Non-GAAP Reconciliation Schedule

Non-GAAP Reconciliation Schedule

2Q 2004 EBITDA Reconciliation 168 DD&A (17) Provision for Income Taxes 222 Net Interest Expense Dollars in millions ($18) Net Income (Loss)* $355 EBITDA* - Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments

2004 YTD EBITDA Reconciliation 329 DD&A (6) Provision for Income Taxes 461 Net Interest Expense Dollars in millions ($8) Net Income (Loss)* $765 EBITDA* (11) Income from Disc. Operations * 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 2Q 2004 Segment Contributions Gas Pipeline E&P Midstream Power Corp/Other Total Segment Profit (Loss) $133 $43 $99 $45 ($15) $305 DD&A 68 46 45 5 4 168 Segment Profit before DDA $201 $89 $144 $50 ($11) $473 General Corporate Expense (28) Investing Income* 13 Other Income (107) TOTAL $355

Gas Pipeline E&P Power 235 - 260 160 - 180 395 - 440 0 - 150 20 - 25 20 - 175 540 - 570 270 - 280 810 - 850 Segment Profit (Loss) DD&A Segment Profit before DDA General Corporate Expense Investing Income Other/Rounding TOTAL RECURRING Midstream 325 - 375 180 - 190 505 - 565 Total 1,100 - 1,400 650 - 700 1,750 - 2,100 (130) - (110) 0 - 50 (20) - (40) 1,600 - 2,000 Corp/Other 0 - 45 20 - 25 20 - 70 Consolidated 2004 Forecast Segment Contribution

Appendix

Exploration & Production 2004 Net Realized Price Calculation Example for any given quarter: * Remaining 2004 hedge position

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 Williams NGL Equity Mix Midstream Domestic NGL Production & Weighted Avg Margins Note: Computed using NGL prices FOB plant tailgate less shrinkage costs. Weighted average is computed using Williams' equity percentages by region. Williams Wtd Avg Net Liquid Margin 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q '04 3Q '04 4Q '04 2005 2Q '05 3Q '05 4Q '05 2006 2Q '06 3Q '06 4Q '06 Wtd Avg Margin 4.64 10.69 14.79 10.32 12.74 2.98 3.95 7.58 9.89 8.4 5-Yr High 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 5-Yr Low 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5-Yr Avg 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 2002 Avg 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 2003 Avg 6.81 6.81 6.81 6.81 5-Yr High 5-Yr Avg 5-Yr Low 2003 Avg 2002 Avg

Enterprise Risk Management Margins & Ad. Assur. $187 $18 $197 - $402 Prepayments - 7 31 - 38 Subtotal $187 $25 $228 $ - $440 Letters of Credit 302 132 196 43 673 Total as of 6/30/04 $489 $157 $424 $43 $1,113 Total as of 3/31/04 $364 $74 $441 $81 $960 Change $125 $83 ($17) ($38) $153 Corp./ E&P Midstream Power Other Total Dollars in millions

Enterprise Risk Management Margin volatility (99% confidence interval) - Incremental liquidity requirement 6/30/04 12/31/03 30 days ($214) ($185) 180 days ($274) ($309) 360 days ($300) ($390) Assumption: The margin numbers above consist of only the forward marginable position values, starting from May 2004. Dollars in millions

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). Midstream figures for 2004 does not include price sensitivity on Canadian assets based on the assumption the Canadian assets would be sold in 2004. Price Increase 2004 2005 2006 1 Power West Spark Spread Power Price (Per MWh) $5.00 $0-5 $5-10 $5-15 2 Midstream Processing Margin NGL Price (Per Gallon) $0.01 $4-10 $10-15 $10-15 3 Estimated dollars in millions

Power Total Undiscounted Cash Flows Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Also, please note that proprietary positions, storage, transportation, transmission, crude and refined products, interest rates, and option premiums are not included. Combined Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($88) ($99) ($396) ($397) ($401) Resale of Tolling $41 $35 $137 $111 $95 Full Requirements ($1) $11 $14 $16 $16 Long-term Physical Forward Power Sales $27 $21 $70 $73 $58 OTC Hedges $36 $37 $169 $69 $125 Tolling Cash Flows Associated With Hedges $7 $34 $155 $261 $282 Subtotal $22 $39 $150 $133 $174 Merchant Cash Flows $0 $0 $7 $18 $71 Est. Combined Power Portfolio Cash Flows $22 $39 $156 $150 $245 Forecasted Direct SG&A ($8) ($14) ($50) ($50) ($50) Forecasted Indirect SG&A ($8) ($6) ($25) ($25) ($25) Subtotal $6 $19 $81 $75 $170 Legacy Portfolio and Other Working Capital $81 $94 $233 $51 $36 Estimated Cash Flows $87 $113 $315 $127 $206

Power West - Total Undiscounted Cash Flows Dollars in millions West Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($39) ($38) ($154) ($154) ($156) Resale of Tolling $41 $35 $86 $0 $0 Long-term Physical Forward Power Sales $29 $24 $59 $0 $0 OTC Hedges $15 $24 $192 $235 $236 Tolling Cash Flows Associated With Hedges $12 $26 $104 $160 $176 Subtotal $58 $70 $287 $241 $256 Merchant Cash Flows $0 $0 $0 $0 $28 Estimated Cash Flows $58 $70 $287 $241 $285

Power Central - Total Undiscounted Cash Flows Dollars in millions Mid-Continent Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006F Tolling Demand Payment Obligations ($13) ($21) ($87) ($88) ($89) Long-term Physical Forward Power Sales ($2) ($3) ($16) $2 $0 OTC Hedges $1 $9 $21 ($11) ($8) Tolling Cash Flows Associated With Hedges ($3) $1 $11 $33 $20 Subtotal ($17) ($15) ($71) ($64) ($77) Merchant Cash Flows $0 $0 $0 $0 $25 Estimated Cash Flows ($17) ($15) ($71) ($64) ($52)

Power East - Total Undiscounted Cash Flows East Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($36) ($39) ($155) ($154) ($157) Full Requirements ($1) $11 $14 $16 $16 OTC Hedges $19 $4 $34 $26 $49 Tolling Cash Flows Associated With Hedges ($1) $7 $41 $67 $87 Subtotal ($18) ($17) ($67) ($44) ($6) Merchant Cash Flows $0 $0 $7 $18 $18 Estimated Cash Flows ($18) ($17) ($60) ($25) $12 Dollars in millions

Consolidated Drivers Dollars in millions