EXHIBIT 99.5

Williams Analyst Conference Call 3rd Quarter 2004 November 4, 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.

3Q04 Review Steve Malcolm, Chairman, President & CEO

Headlines Results show discipline Stronger balance sheet, moving towards growth Debt reduction efforts ahead of schedule 3Q 2003 $13.0 billion 3Q 2004 $ 8.9 billion Year to date CFFO from continuing operations almost double 3Q 2003 $567 million 3Q 2004 $1.1 billion Debt to total book capitalization significantly reduced 3Q 2003 75.6% 3Q 2004 69.1% Using capital with discipline to complete announced projects Focus shifting from turnaround to growth, value creation

Headlines for the Quarter Williams delivers strong 3Q performance Exploration & Production production volumes continue to increase Midstream has another outstanding quarter, despite Hurricane Ivan Gas Pipeline steady performance Power continues positive cash flows Consolidated strong cash flows continue

Headlines Williams ceases efforts to sell Power business Natural gas businesses continue as focal point for strategy, investment Company has greater financial strength, lower Power liquidity requirements Adoption of hedge accounting expected to reduce earnings volatility Residual impact of MTM will depress future reported earnings; cash flow guidance positive and unaffected Hedges in place to significantly cover power contract obligations through 2010 Decision strengthens position to continue optimization of power contracts beyond 2010 Will continue focus on hallmarks of Power's recent success Risk reduction Cash generation Continue meeting contractual commitments

Headlines Williams poised for growth, value-creation Natural gas businesses provide growth opportunities Investments today preserve, enhance competitive position and create value Drilling activity, production levels both increase Deepwater Gulf and West infrastructure prime for incremental business Gulfstream expansion nearly complete Power pursuing contracts to reduce future risk Scale and scope of investments in primary gas businesses could ramp up in 2005 - 2007 Focused on disciplined growth that creates EVA and shareholder value

Midstream Complete deepwater projects Complete asset sales Enhance competitive position- consider 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 Accelerate Piceance drilling Powder River permits and dewatering Early debt retirement New credit facilities Cost reductions Support growth Examine dividend level Spark spreads improve Risk Reduction Solid Financial Footing Disciplined Growth Continue to reduce risk, generate cash, meet commitments Continue production growth

Financial Results & 2004 Outlook Don Chappel, CFO

3rd Quarter YTD 2004 2003 2004 2003 Income (Loss) from Continuing Ops.* $16 $20 ($3) $91 Income (Loss) from Discont. Ops.* 83 86 93 232 Effect of Accounting Change - - - (761) Net Income/(Loss)* $99 $106 $90 ($438) Net Income/(Loss) Share* $0.19 $0.20 $0.17 ($0.89) Recurring. Inc./(Loss) from Cont. Ops Avail to Common Shareholders** $136 ($0) $193 ($56) Rcr. Inc./(Loss) from Cont. Ops /Share** $0.26 ($0.00) $0.37 ($0.10) Financial Results * Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Notes 2 & 4 of the current 10Q). ** 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. $16 $20 ($3) $91 Gains on Sale of Assets - (47) - (320) Impairments/Losses/Write-offs 16 9 39 158 Income (Expense) Related to Prior Periods 17 (1) 11 (108) Debt Retirement Expenses 155 - 252 - Other - Net 6 5 15 33 Less: Income Tax Provision 74 (14) 121 (119) Recurring Income from Cont. Ops. $136 ($0) $193 ($27) Preferred Dividend - - - (29) Rec. Inc./(Loss) from Cont. Ops. Avail. to Com. $136 ($0) $193 ($56) Recurring Income/(Loss) from Cont. Ops/Share $0.26 ($0.00) $0.37 ($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. 3rd Quarter YTD

Mark to Market Adjustments Dollars in millions, except for per-share amounts 3rd Quarter YTD 2004 2003 2004 2003 Recurring income from continuing operations available to common shareholders 136 $ (0) $ 193 $ (56) $ Recurring diluted earnings per common share 0.26 $ (0.00) $ 0.37 $ (0.10) $ Mark-to-Market (MTM) adjustments for Power: 1 Reverse forward unrealized MTM gains/losses (187) 54 (279) (138) Add realized gains/losses from MTM previously recognized 45 (45) 192 (55) Total MTM adjustments (142) 9 (87) (193) Tax effect of total MTM adjustments (at 39%) (55) 4 (34) (75) After tax MTM adjustments (87) 5 (53) (118) Recurring income from cont. operations avail. to common shareholders after MTM adjustments 49 $ 5 $ 140 $ (174) $ Recurring diluted earnings per share after MTM adjustments 0.09 $ 0.01 $ 0.27 $ (0.33) $ (1) Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. Note: 2Q recurring income has been reduced by $16.5 mm (pretax) for Devil's Tower to reflect the third quarter change from recognizing revenues on the fixed fee received over a defined term to a units-of-production method that recognizes revenues as volumes are delivered for the life of the reserves. A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com.

2004 2003 2004 2003 Segment Profit* $436 $319 $1,006 $1,199 Net Interest Expense (196) (265) (657) (1,000) Debt Retirement Expense (155) - (252) - Other Income (Expense) - Net (21) (11) (58) 28 Income from Cont. Ops. Before Tax* 64 43 39 227 Provision for Income Tax 48 23 42 136 Income/(Loss) from Continuing Ops.* $16 $20 ($3) $91 Income from Discontinued Ops. 83 86 93 232 Effect of Accounting Change - - - (761) Net Income/(Loss)* $99 $106 $90 ($438) Net Income Components * Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Notes 2 & 4 of the current 10Q). Dollars in millions (except per share amounts) 3rd Quarter YTD

Third Quarter Segment Profit Reported Recurring 3Q04 3Q03 3Q04 3Q03 Gas Pipeline $149 $142 $149 $142 Exploration & Production 70 59 70 59 Midstream Gas & Liquids 105 77 128 70 Power(1) 109 37 109 15 Other 3 4 3 (5) Segment Profit(2) $436 $319 $459 $281 Dollars in millions (1) Power includes unrealized MTM loss of ($54) million in 3Q03 and unrealized MTM gain of $187 million in 3Q04. (2) Reported segment profit Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Notes 2 & 4 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 $429 $407 $438 $434 Exploration & Production(1) 165 351 176 260 Midstream Gas & Liquids 312 247 318 240 Power(2) 121 236 121 (34) Other (21) (42) (3) (2) Segment Profit(3) $1,006 $1,199 $1,050 $898 Dollars in millions (1) E&P YTD reported results include $11 million loss provision related to prior periods. (2) Power 2003 reported results include $108 million income for prior period item correction. Power also includes unrealized MTM gains of $185 million in 2003 and $279 million in 2004. (3) Reported segment profit Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Notes 2 & 4 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 3Q2003 $281 Power 94 - Higher unrealized MTM gains +$242 million - Lower gains on contract suspension -$126 million - Lower realized margins and SG&A -$22 million Midstream 57 - Higher NGL margins +$45 million - Improved olefins results +$17 million - Impact of Hurricane Ivan -$5 million Gas Pipeline 7 - Evergreen/Gulfstream earnings +$15 million - Depreciation adjustment +$4 million - 2003 Excess royalties reversal -$7 million - Lower short term firm revenues -$5 million Exploration & Production 11 - Higher production volumes +$10 million - Higher net realized price +$6 million - Higher operating costs -$5 million Other 9 Recurring Segment Profit 3Q2004 $459 Major Changes in Recurring Segment Profit Dollars in millions

3Q04 YTD04 Beginning Cash * $1,030 $2,318 Cash Flow from Continuing Operations 462 1,065 Cash Flow from Discontinued Operations 11 23 Asset Sales 618 1,013 Restricted Investments (LC Collateral) - 380 Debt Retirements (816) (3,036) Capital Expenditures/Investments (209) (540) Debt Premiums/Issuance Costs (140) (240) Other-Net 21 (5) Ending Cash @ 9/30/04* $977 $977 Change in Cash ($53) ($1,341) Restricted Cash (not included above) $93 $93 Cash Information Dollars in millions * Includes cash for discontinued operations of $2.5 million at 12/31/03 and $0 million at 9/30/04

Debt Balance Debt Balance @ 12/31/03 * $11,978 7.7% Scheduled Debt Retirements & Amortization (801) Tendered Debt Retirements (1,964) Open Market Purchases (269) Debt Balance @ 9/30/04 $8,944 7.3% FELINE PACS Exchange (827) Estimated Debt Balance @ 10/22/04 $8,117 7.3% Total Debt Reduction @ 10/22/04 ($3,861) Fixed Rate Debt @ 9/30/04 $8,355 7.5% Variable Rate Debt @ 9/30/04 $589 4.1% Avg. Cost * Debt is long-term debt due within 1 year plus long-term debt plus notes payable; includes FELINE PACS Dollars in millions

2004 Forecast EBITDA Reconciliation Dollars in millions Net Income $25 - $160 $115 - $275 Income from Disc. Operations (50) - (100) (160) - (185) Net Interest 810 - 860 820 - 860 DD&A 660 - 710 650 - 700 Prov. (Benefit) for Income Taxes 0 - 80 (5) - 125 Other/Rounding 5 - 40 (70) - 25 EBITDA $1,450 - $1,750 $1,350 - $1,800 Early Debt Retirement Fees 300 - 250 250 - 200 EBITDA Excl. Early Debt Fees $1,750 - $2,000 $1,600 - $2,000 Aug. 5 Guidance Nov. 4 Guidance

Consolidated 2004 Segment Profit Guidance Dollars in millions 2004 Forecast Gas Pipeline $550 - 570 Exploration & Production 235 - 260 Midstream 435 - 485 Other/Rounding (45) - (40) $1,175 - 1,275 Power 0 - 100 Total $1,175 - 1,375 325 - 375 0 - 45 $1,100 - 1,400 $1,100 - 1,250 0 - 150 540 - 570

Segment profit $1,175 - $1,375 $1,100 - $1,400 Net Interest Expense (810) - (860) (820) - (860) Early Debt Retirement Costs (300) - (250) (250) - (200) Other (Primarily General Corp. Costs) (90) - (125) (80) - (125) Pretax Income (Loss) ($25) - $140 ($50) - $215 Provision (Benefit) for Income Tax 0 - (80) 5 - (125) Income / (Loss) from Continuing Ops (25) - 60 (45) - 90 Income from Discontinued Ops 50 - 100 160 - 185 Net Income (Loss) - Reported $25 - $160 $115 - $275 Diluted EPS - Reported $0.05 - $0.30 $0.22 - $0.52 Net Income - Recurring * $183 - $238 $107 - $212 Diluted EPS - Recurring * $0.34 - $0.44 $0.20 - $0.40 Diluted EPS- Recurring After MTM Adjustments $0.26 - $0.36 Dollars in millions, except per-share amounts Consolidated 2004 Forecast Guidance * Excludes early debt retirement costs, gains and losses on assets sales and impairments Aug. 5 Guidance Nov. 4 Guidance

Business Unit Results

Exploration & Production Ralph Hill, Senior Vice President

3rd Quarter YTD 2004 2003 2004 2003 Exploration & Production Segment Profit Dollars in millions Segment Profit $70 $59 $165 $351 Non recurring: Ownership issue - - 11 - Gain on sale of assets - - - (91) Recurring Segment Profit $70 $59 $176 $260 3Q04 to 3Q03 increase includes $10 million due to higher production volumes net of associated costs $6 million due to higher realized gas price net of higher direct taxes ($5) million due to higher costs for insurance, legal fees and other Base business sequential quarter improved Volumes increased by 5% Recurring profit increased 27% $58mm negative hedge impact in 3rd quarter, $159mm negative hedge impact year to date

1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q '04 3Q '04 Retained Properties 130.6 111.7 101.2 90.3 94 101.1 123.3 Sold Properties 9.3 9.3 Exploration & Production Third Quarter Accomplishments Recurring Segment Profit + Depreciation* Piceance volumes up 15% from last quarter Big George volumes up 10% to 68 MMcfd Add'l Powder River permits received, WMB up to 424 Piceance Trail Ridge area flows to sales in October Piceance Ryan Gulch area drilling commences San Juan program on track Expanded firm takeaway capacity Overall production has grown 18% since beginning of year

Ryan Gulch is north of existing Piceance production, and adjacent to a major pipeline hub Entered area through farm-in Spud first well in 3rd Quarter Commitment to drill 3 wells in '05, increasing in following years 15,000 net acres Exploration & Production Piceance area - Ryan Gulch Area Shown Area Shown Denver

Exploration & Production 2005-06 Guidance Reconciliation

Exploration & Production Year-Over-Year Performance Dollars in millions 2004 2005 2006 Segment profit $235 - 260 $400 - 475 $450 - 525 Midpoint of range $247 $437 $487 Incremental increase +$190 +$50 Price impact +$98 ($29) Volumes (including new projects) +$92 +$79 Production (MMcfe/d) 525 - 550 600 - 700 700 - 800 Yearly growth +21% +15%

Exploration & Production 2004-2006 Guidance Note: If guidance has changed, previous guidance from 8/5/04 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 $400 - 475 $450 - 525 Annual DD&A $160 - 180 $220 - 250 $250 - 290 Capital spending $400 - 450 $500 - 575 $525 - 625 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 $400 - 450 $450 - 500 $195 - 225 $230 - 260 $375 $425

Midstream Alan Armstrong, Senior Vice President

3rd Quarter YTD 2004 2003 2004 2003 Segment Profit $105 $77 $312 $247 Non recurring: Depreciable Life Adjustment 6 4 6 4 Gain on Asset Sales - (11) - (11) Rev. Recognition Adjust. to 2Q 17 - - - Recurring Segment Profit $128 $70 $318 $240 Dollars in millions Midstream Segment Profit 3Q04 vs. 3Q03 increase includes $45 million due to higher NGL Margins $17 million due to better performance in Olefins ($5) million negative impact of Hurricane Ivan

Midstream Third Quarter Accomplishments Near record margins Hurricane Ivan repair progress Closed Canadian straddle plants sale, $190 million in 3Q PSA signed for Ethylene Distribution System, $28 million cash in 4Q Completed negotiations of Gulf Liquids dispute $85 million cash in 4Q $95-100 million gain in 4Q * 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 152 97 110 105 2004 150 128 172 Recurring Segment Profit + Depreciation*

Midstream Domestic NGL Actual Average Net Margin by Qtr. Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 5.21 7.7 11.75 12.75 17.16 7.99 6.18 11.01 10.08 8.84 17.64 Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc.

Midstream 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit $435-485 $310-410 $400-500 Annual DD&A $175-185 $180-190 $185-195 Capital Spending $95-105 $120-140 $110-130 $325-375 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 8/5/04 is shown in italics directly below $170-180 $90-110 $175-185 $60-80 $350-450 $175-185 $50-70 Capital Spending Increase New Well Connects: $10 $10 New Expansion: $40 $45 Efficiency: $10 $5 $300-400

Midstream Segment Profit + DDA & Capital Spending 0 100 200 300 400 500 600 700 $ MM New Expansion Segment Profit Forecast Margin Uplift Segment Profit (Q4) Actual Margin Uplift Segment Profit (thru Q3) Base Segment Profit + DDA* Old Expansion New Expansion Mandatory, Reliability & Efficiency Well Connects Dollars in Millions * Segment Profit is Recurring & Restated; 2004-2006 segment profit + DDA reflects midpoint of ranges, Capital Spending reflects midpoint of ranges. Operating Profit Capital Projects 2002 2003 2004 2005 2006

Gas Pipeline Doug Whisenant, Senior Vice President

Gas Pipeline Segment Profit 3rd Quarter YTD 2004 2003 2004 2003 Segment profit $149 $142 $429 $407 Includes: Write-off software project - - - 26 Write-off of previously capitalized cost for idled segment - - 9 Recurring Segment Profit $149 $142 $438 $434 Dollars in millions 3Q04 vs. 3Q03 increase includes $10 million for Evergreen incremental project $5 million due to increased Gulfstream earnings $4 million depreciation adjustment $4 million improvement compared to 2003 T&E imbalance write-off ($5) million lower short-term firm sales ($7) million 2003 excess royalties reversal ($2) million due to IT revenue sharing

Gas Pipeline Third Quarter Accomplishments Gulfstream Peak day delivery record set 9/7/04 Phase II construction began 7/21/04 Central New Jersey expansion project filed with FERC Leidy to Long Island expansion; binding 100 MDtd, 20-year term Began design, environmental and permitting work for 26" Replacement Everett Delta Lateral construction completed 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2003 209.1 202.5 203.2 213.8 2004 207.8 203 211.7

2004 2005 2006 Segment profit1 $550 - 570 $525 - 575 $525 - 575 Annual DD&A2 $265 - 275 $280 - 290 $290 - 300 Capital spending $260 - 300 $370 - 420 $475 - 550 Dollars in millions Gas Pipeline 2004-2006 Guidance $350 - 400 $450 - 520 $280 - 320 $270-280 Note: 1) Reported income and includes $9 million non-recurring charge in 2Q '04 2) Includes $10 million favorable adjustments in 2004 - If guidance has changed, previous guidance from 8/5/04 is shown in italics directly below $540 - 570

Gas Pipeline 2004-2006 Capital Spending Detail $475 - 550 $370 - 420 $260 - 300 Total 10 - 20 20 - 30 30 - 40 255 - 275 50 - 65 35 - 40 60 - 70 $180 - 210 $220 - 235 $135 - 150 Normal Maintenance 2006 2005 2004 Dollars in millions $450 - 520 35 - 45 $350 - 400 Clean Air Act NWP 26" Restore/Replace Expansion 80 - 90 30 - 45 20 - 30 260 - 300 140 - 155 195 - 215 70 - 75 $280 - 320 90 - 100 35 - 45 Note: - Includes Pipeline Safety expenditures as detailed in the 10-Q/10-K Amounts include AFUDC If guidance has changed, previous guidance from 8/5/04 is shown in italics directly below 140 - 150 45 - 55

Power Bill Hobbs, Senior Vice President

Portfolio continues to generate positive cash flows Market conditions continue to slowly rebound Improving market liquidity Spark spreads are stabilizing Favorable political messages from California and FERC Cash management continues to improve New risk reducing contracts Favorable California PUC decision Adoption of hedge accounting Lowers earnings volatility Residual MTM impact lowers future reported earnings Segment profit after MTM adjustments unchanged No effect on cash flow guidance Power Key Messages

3rd Quarter YTD 2004 2003 2004 2003 Power Segment Profit Dollars in millions Gross Margin $131 $60 $202 $198 SG&A (20) (26) (56) (107) Op. Exp. & Other Inc / (Exp) (3) 4 (25) 150 Equity Earnings (Losses) 1 (1) 0 (5) Segment Profit $109 $37 $121 $236 Includes: Aux Sable Impairment - 6 - 14 Regulatory Settlement - - - 20 Prior period correction* - (1) - (108) Gains on sale of assets/contracts - (27) - (208) Reduction in force costs - - - 12 Recurring Segment Profit $109 $15 $121 ($34) * 2003 amounts reflect corrections as disclosed in 2003 10-K

Power Segment Profit to Cash Flow Dollars in millions

Power Segment Undiscounted Cash Flows Variance Analysis 4Q03 4Q02 2003 2002 Dollars in millions Dollars in millions Note: Q3 2004 forecast estimated as of 6/30/04. Combined Power Portfolio Actual Q3'04 v. Forecast Q3'04 3Q04 A 3Q04 F YTD'04 A YTD'04 F Tolling Demand Payment Obligations ($126) ($125) ($313) ($307) Resale of Tolling 29 25 105 102 Full Requirements 4 0 14 1 Long-term Physical Forward Power Sales 18 12 66 62 OTC Hedges 44 57 117 140 Merchant Cash Flows 80 93 121 124 Total Cash Flows $49 $62 $110 $122 Legacy Portfolio and Other Working Capital 281 37 456 32 Direct SG&A (13) (14) (35) (41) Indirect SG&A (7) (6) (21) (18) Estimated Cash Flows After SG&A $310 $79 $510 $95

Dollars in millions 1Schedule of expected realization of MTM gains/losses previously recognized is included in the Appendix. Power Segment Profit after MTM Adjust. Forecast

2004 2005 2006 Previous Segment Profit Guidance $0 - $150 $50 - $150 $50 - $200 Current Forecast: Segment Profit after MTM Adjustment (20) 100 154 MTM Adjustments 67 (254) (269) Segment Profit $47 ($154) ($115) Revised Segment Profit Guidance $0 - $100 ($200) - ($100) ($200) - ($50) Cash Flow from Operations $150 - $350 $50 - $150 $50 - $200 Capital Expenditures $0 $0 $0 Dollars in millions Power 2004-2006 Guidance

Power Summary Portfolio continues to generate positive cash flows Managing business to maximize cash flows, reduce risk and honor commitments Accounting change does not impact cash flow guidance or economic value Continued focus on greater reporting transparency Next Power Tutorial on November 18

Financial Overview & 3-Year Outlook Don Chappel

$1,100 - 1,400 (50) 125 - 25 1,175 - 1,375 1,225 - 1,425 660 - 710 1,250 - 1,450 775 - 875 $1,300 - 1,600 (250) 0 1,050 - 1,350 1,300 - 1,600 700 - 775 1,300 - 1,600 1,000 - 1,200 $1,400 - 1,700 (250) 50 1,200 - 1,500 1,450 - 1,750 750 - 850 1,450 - 1,750 1,150 - 1,350 Segment Profit: Prior Guidance Power Changes Other BU Changes New Guidance After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Consolidated 2004 - 2006 Outlook 2006 2004 650 - 700 1,000 - 1,300 Note: If guidance has changed, previous guidance from 8/5/04 is shown in italics directly below 700 - 800 1,400 - 1,700 900 - 1,100 650 - 750 800 - 1,000 2005 Dollars in millions

90 - 110 280 - 320 2004 2005 2006 Exploration & Production $400 - 450 $500 - 575 $525 - 625 Midstream 95 - 105 120 - 140 110 - 130 Gas Pipeline 260 - 300 370 - 420 475 - 550 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $775 - 875 $1,000 - 1,200 $1,150 - 1,350 Dollars in millions Consolidated 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 8/5/04 is shown in italics directly below 400 - 450 60 - 80 350 - 400 $800 - 1,000 450 - 500 50 - 70 450 - 520 $900 - 1,100

Consolidated Guidance Trends 2004 2005 2006 2007 SP Old-Low 1225 1300 1450 1550 SP Old-High 1425 1600 1750 2050 SP New-Low 1175 1050 1200 1300 SP New-H 1375 1350 1500 1800 Cap Ex-Low 775 1000 1150 900 Cap Ex-High 875 1200 1350 1200 $1,000 to $1,200 $1,150 to $1,350 $900 to $1,200 $ Millions $775 to $875 $1,300 to $1,800 $1,175 to $1,375 Segment Profit Cap Ex $1,300 to $1,600 $1,450 to $1,750 $1,550 to $2,050 $1,225 to $1,425 Seg. Profit w/o Resid MTM Impact $1,050 to $1,350 $1,200 to $1,500 Preliminary Estimate

Consolidated Progress as Promised 2003 2004 2005 2006 CFFO-Low 570 1250 1300 1450 CFFO-High 570 1450 1600 1750 Debt to Cap 0.745 0.623 0.591 0.57 0.633 0.601 0.59 Cash Flow 1 Debt / Cap 2 75% Increasing Cash Flow 570 $1,250 to $1,450 $1,300 to $1,600 $1,450 to $1,750 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% to 63% 59% to 60% 57% to 59% Decreasing Debt / Cap %

Received tenders to exchange $827 million Issued 33.1 million common shares on Oct. 22 Paid cash of $49 million; expect pre-tax charge of $25 million in 4Q04 First remarketing for remaining $273 million debt scheduled for Nov. 16 Williams may choose to purchase some of the notes Remaining units exchanged into common on Feb. 16, 2005 Consolidated FELINE PACS Update

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 31 247 119 323 640 53 221 1018 998 757 751 292 100 1170 850 300 Remaining PACS 273 Dollars in millions

Drive/enable sustainable growth in EVA(r)/ shareholder value Maintain a cash/liquidity cushion of $1.0 billion plus Continue to steadily improve credit ratios/ratings; ultimately achieving investment grade ratios Reduce risk in Power segment Increase focus and disciplined EVA(r) -based investments in natural gas businesses Consider dividend policy Combination of growth in operating cash flows and reduction in interest costs drives value creation Consolidated Financial Strategy/Key Points

Summary Steve Malcolm

Midstream Complete deepwater projects Complete asset sales 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 Accelerate Piceance drilling Powder River permits and dewatering Early debt retirement New credit facilities Cost reductions Support growth Examine dividend level Spark spreads improve Risk Reduction Solid Financial Footing Disciplined Growth Continue to reduce risk, generate cash, meet commitments Continue production growth Enhance competitive position- consider MLP

Summary 3rd quarter results strong Restructuring nears the finish line Asset sales program essentially completed Adequate liquidity continues Pursuing growth opportunities Retaining Power and continuing strategy to Reduce risk Generate cash Meet contractual commitments

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 Scorecard Update

Non-GAAP Reconciliations

Non-GAAP Reconciliation Schedule

Non-GAAP Reconciliation Schedule

Non-GAAP Reconciliation Schedule Dollars in millions except for per share amounts 2004 2003 1Q 2Q 3Q 1Q 2Q 3Q Recurring income from continuing operations available to common shareholders 3 $ 54 $ 136 $ (44) $ (12) $ (0) $ Recurring diluted earnings per common share 0.00 $ 0.10 $ 0.26 $ (0.08) $ (0.02) $ (0.00) $ Mark-to-Market (MTM) adjustments for Power: * Reverse forward unrealized MTM gains/losses (23) (69) (187) 40 (232) 54 Add realized gains/losses from MTM previously recognized 137 10 45 (55) 45 (45) Total MTM adjustments 114 (59) (142) (15) (187) 9 Tax effect of total MTM adjustments (at 39%) 44 (23) (55) (6) (73) 4 After tax MTM adjustments 70 (36) (87) (9) (114) 5 Recurring income from cont. operations avail. to common shareholders after MTM adjust. 73 $ 18 $ 49 $ (53) $ (126) $ 5 $ Recurring diluted earnings per share after MTM adjustments 0.14 $ 0.03 $ 0.09 $ (0.10) $ (0.24) $ 0.01 $ weighted average shares - diluted (thousands) 525,752 521,698 529,525 517,652 534,839 524,711 * Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives.

3Q 2004 EBITDA Reconciliation 167 DD&A 48 Provision for Income Taxes 196 Net Interest Expense Dollars in millions $99 Net Income* $427 EBITDA* (83) Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments

2004 YTD EBITDA Reconciliation 495 DD&A 42 Provision for Income Taxes 657 Net Interest Expense Dollars in millions $90 Net Income* $1,191 EBITDA* (93) 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 3Q 2004 Segment Contributions Gas Pipeline E&P Midstream Power Corp/Other Total Segment Profit (Loss) $149 $70 $105 $109 $2 $436 DD&A 63 52 44 5 3 167 Segment Profit before DDA $212 $122 $149 $114 $5 $602 General Corporate Expense (24) Investing Income* (7) Other Income (145) TOTAL $427

Gas Pipeline E&P Power 235 - 260 160 - 180 395 - 440 0 - 100 20 - 25 20 - 125 550 - 570 265 - 275 815 - 845 Segment Profit (Loss) DD&A Segment Profit before DDA General Corporate Expense Investing Income Other/Rounding TOTAL Midstream 435 - 485 175 - 185 610 - 670 Total 1,175 - 1,375 660 - 710 1,835 - 2,085 (125) - (110) 0 - 50 40 - (25) 1,750 - 2,000 Corp/Other (45) - (40) 40 - 45 (5) - 5 Consolidated 2004 Forecast Segment Contribution 540 - 570 270 - 280 810 - 850 325 - 375 170 - 180 495 - 555 0 - 150 20 - 175 0 - 45 30 - 35 30 - 80 1,100 - 1,400 650 - 700 1,750 - 2,100 (130) - (110) (20) - (40) 1,600 - 2,000

Dollars in millions, except per-share amounts Consolidated 2004 Forecast Guidance Net Income / (Loss) Reported $25 - $160 Less: Discontinued Operations (50) - (100) Net Income / (Loss) Continuing Ops Reported ($25) - $60 Adjustments: Early Debt Retirement Costs (Pretax) 300 - 250 Other Non-Recurring Items (Pretax) 41 Total Non-Recurring Pretax 341 - 291 Less Taxes @ 39% (133) - (113) Total Non-Recurring After Tax 208 - 178 Recurring Net Income $183 - $238 Recurring EPS $0.34 - $0.44 Mark-to-Market Adjustment Less Taxes @ 39% Mark-to-Market Adjust. After Tax Recurring Net Income After MTM Adjustments Recurring EPS After MTM Adjustments (68) 26 (41) $142 - $197 $0.26 - $0.36

Appendix

Exploration & Production Net Realized Price Calculation

Midstream Domestic NGL Quarterly Average Net Margins Note: Computed using NGL prices FOB plant tailgate less shrinkage costs, transportation and fractionation. Average is weighted using Williams' equity liquids percentages by region: 50% Rockies, 35% Gulf Coast and 15% San Juan. 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q '04 3Q '04 Qtr Avg Net Margin 4.37 11.77 15.83 10.34 12.77 3.01 3.98 7.62 9.86 8.83 23.63 5-Yr High 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 5-Yr Avg 9.25 9.25 9.25 9.25 9.25 9.25 9.25 9.25 9.25 9.25 9.25 5-Yr Low 5.34 5.34 5.34 5.34 5.34 5.34 5.34 5.34 5.34 5.34 5.34 2002 Avg 10.58 10.58 10.58 10.58 2003 Avg 6.85 6.85 6.85 6.85 2004 - 3Q Avg 14.11 14.11 14.11

Enterprise Risk Management Margins & Ad. Assur. $19 $2 $133 - $154 $527 Prepayments - 5 32 - 37 151 Subtotal $19 $7 $165 $ - $191 $678 Letters of Credit 429 184 204 114 931 378 Total as of 9/30/04 $448 $191 $369 $114 $1,122 $1,056 Total as of 6/30/04 $489 $157 $424 $43 $1,113 Change ($41) $34 ($55) $71 $9 Corp./ 12/31/03 E&P Midstream Power Other Total Total Dollars in millions As of 9/30/04

Enterprise Risk Management Margin volatility (99% confidence interval) - Incremental liquidity requirement 9/30/04 12/31/03 30 days ($118) ($185) 180 days ($234) ($309) 360 days ($336) ($390) Assumption: The margin numbers above consist of only the forward marginable position values, starting from November 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 $3-5 $10-15 $10-15 3 Estimated dollars in millions

Dollars in millions (estimated as of 9/30/04) Power Future Hedge Realization 1Represents the fair value and expected future realization of those derivatives which qualify for hedge accounting under SFAS 133. Future changes in fair value will be reported in OCI on the balance sheet, and then re-classified into earnings in the period in which the hedged transaction, or underlying, affects earnings.

Dollars in millions Power Derivative Net Asset Reconciliation Balance at 9/30/04 Power - Fair Value of Designated FAS 133 Hedges1 $979 Power - Other Derivatives (134) E&P - Fair Value of Designated FAS 133 Hedges (612) Corporate 12 Net Derivative Assets Per Balance Sheet $244 1Represents the fair value of those derivatives which qualify for hedge accounting under SFAS 133. Future changes in fair value will be reported in OCI on the balance sheet, and then re-classified into earnings in the period in which the hedged transaction, or underlying, affects earnings.

Power Total Undiscounted Cash Flows Note: Actual cash flows realized may differ materially from those shown.

Power West - Total Undiscounted Cash Flows Dollars in millions Note: Actual cash flows realized may differ materially from those shown.

Power Central - Total Undiscounted Cash Flows Dollars in millions Note: Actual cash flows realized may differ materially from those shown.

Power East - Total Undiscounted Cash Flows Dollars in millions Note: Actual cash flows realized may differ materially from those shown.

Consolidated Effective Tax Rates Combined Continuing Ops. Discontinued Ops. Third Quarter 2004 Federal $46 35% $23 35% $23 35% State 19 15% 16 25% 3 5% Foreign (41) (31%) 2 3% (43) (65%) Other 8 6% 7 11% 0 0% Tax Provision $32 25% $48 74% (17) (25%) Year to Date 2005 Federal $42 35% $14 35% $28 35% State 15 12% 12 31% 3 4% Foreign (36) (30%) 7 18% (44) (54%) Other 9 8% 9 23% 0 0% Tax Provision $30 25% $42 107% (13) (15%) 2004 2005 2006 Effective Tax Rate Guidance* See above 39% 39% Cash Tax Rate Guidance 3-5% 3-5% 4-8% Dollars in millions An additional $25 million income tax expense is forecast in 2005 & 2006 Note: If guidance has changed, previous guidance from 8/5/04 I s shown in italics directly below

Consolidated Drivers Dollars in millions