The Williams Companies, Inc. 8K Williams Reports Third-Quarter 2005 Financial Results | WMB 3 Nov 05

Exhibit 99.2

Williams 2005 3rd Quarter Earnings Release November 3, 2005

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" within the meaning of the 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 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; 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; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; 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 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 our business; 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 have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; 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 natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. 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. Forward Looking Statements

Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable" reserves and "possible" reserves and "new opportunities potential" reserves that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to "total resource portfolio" include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our Web site at www.williams.com.

3Q05 Review Steve Malcolm Chairman, President & CEO

3rd Quarter Headlines Recurring earnings after mark-to-market effect climb nearly 150% over year-ago level Exploration & Production growth continues Continued strength in liquids margins drive Midstream results higher Gas Pipeline continues steady performance Mild weather, high gas prices, hurricanes combine to depress Power results Overview

Headlines E&P ready to ramp up pace of growth again with arrival of new rigs in Piceance Basin Midstream captures significant deepwater production commitment, prepares to expand capacity in West Gas Pipeline continues to expand system to meet demand of growth markets Power completes deal to resell 1,500 megawatts of tolling rights through 2010 Planning sale to Williams Partners L.P. of about 25% interest in gathering and processing assets in Four Corners area Raising capital expenditure and profit guidance Overview

Effect of Hurricanes Overall effect on Williams expected to be minimal Interstate pipelines provided continuous service For Midstream, Katrina and Rita reduced volumes in the Gulf of Mexico area, but boosted margins in its western business Moving incremental volumes - stranded gas - via new interconnects on Discovery Contributed to depressed Power results Pushed delivery of first of 10 new FlexRig4? rigs in Piceance Basin to end of this month Overview

Financial Results and 2005 Outlook Don Chappel CFO

Financial Results Dollars in millions (except per share amounts) 3rd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $5 $16 $249 ($2) Income (Loss) from Disc. Operations (1) 83 (2) 92 Net Income (Loss) $4 $99 $247 $90 Net Income (Loss)/Share $0.01 $0.19 $0.42 $0.17 Recurring Income (Loss) from Cont. Ops./Share ($0.01) $0.26 $0.44 $0.37 Recurring Inc. from Cont. Ops. After MTM Adjustments/Share $0.22 $0. 09 $0.60 $0.27 Consolidated 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 Income from Cont. Operations 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. Consolidated Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $6 $16 $249 ($2) Nonrecurring Items Impairments/Losses/Write-offs 5 16 61 41 Expense related to Prior Periods - - 17 (28) 11 Gain on Sale of Assets (22) - - (38) - - Debt Retirement Expense - - 155 - - 252 Other - Net - - 6 18 13 Total nonrecurring (17) 194 13 317 Tax Effect of Adjustments (6) 74 2 121 Recurring Income (Loss) from Continuing Operations Available To Common ($5) $136 $260 $194 Recurring Income (Loss) from Continuing Operations/Share ($0.01) $0.26 $0.44 $0.37

3rd Qtr YTD 2005 2004 2005 2004 Recurring Income from Cont. Operations After Mark-to-Market Adjustments Note: Adjustments have been made to reverse estimated forward unrealized MTM gains (losses) and add estimated realized gains from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com. Dollars in millions, except for per-share amounts Recurring Inc. (Loss) from Cont. Ops. Avail. To Common ($5) $136 $260 $194 Recurring Diluted Earnings (Loss) per Common Share ($0.01) $0.26 $0.44 $0.37 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains) losses 153 (187) (90) (280) Add realized gains from MTM previously recognized 60 45 250 193 Total MTM adjustments 213 (142) 160 (87) Tax Effect of Total MTM Adjustments (at 39%) 83 (55) 62 (34) After-tax MTM Adjustments 130 (87) 98 (53) Recurring income from Continuing Operations Avail. To Common Shareholders After MTM Adjustments $125 $49 $358 $141 Recurring Diluted Earnings Per Share After MTM adjustments $0.22 $0.09 $0.60 $0.27 Consolidated

Net Income Components 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. Consolidated 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $205 $436 $971 $1,008 Net Interest Expense (164) (197) (491) (657) Debt Retirement expense - - (155) - - (252) Other Income (Expense) - Net (38) (19) (62) (58) Income from Cont. Ops. Before Tax 3 65 418 41 Provision for Income Tax (2) 49 169 43 Income (Loss) from Continuing Ops. 5 16 249 (2) Income (Loss) from Discontinued Ops. (1) 83 (2) 92 Net Income $4 $99 $247 $90

Third Quarter Segment Profit 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. Dollars in millions Exploration & Production $159 $70 $137 $70 Midstream Gas & Liquids 121 105 121 128 Gas Pipeline 161 149 147 149 Power (226) 109 (226) 109 Other (10) 3 (10) 3 Segment Profit $205 $436 $169 $459 MTM Adjustments - Power 213 (142) Segment Profit after MTM Adjustments $382 $317 Memo: Power after MTM adjustments $(13) $(33) Consolidated Reported Recurring 3Q05 3Q04 3Q05 3Q04

2005 YTD Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $38 $165 $352 $176 Midstream Gas & Liquids 359 314 359 320 Gas Pipeline 493 429 444 438 Power (187) 121 (162) 121 Other (75) (21) (23) (3) Segment Profit $971 $1,008 $970 $1,052 MTM Adjustments 160 (87) Segment Profit after MTM Adjustments $1,130 $965 Memo: Power after MTM adjustments ($2) $341 Dollars in millions Consolidated 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. 1 Includes impact of legacy natural gas portfolio that liquidated in 1Q04.

Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 3Q04 $317 Exploration & Production 67 - Higher production volumes +$14million - Higher net realized price +$82 million - Impact of hedge ineffectiveness -$16 million Midstream (7) - Decreased NGL margins -$11 million - Increased processing fees +$7 million Gas Pipeline (2) - Increased Gulfstream earnings +$5 million - Grays Harbor contract termination -$5 million Power 20 - Absence of interest rate losses +$15 million Other (13) Recurring Segment Profit after MTM Adj. 3Q05 $382 Dollars in millions

Cash Information Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS 2 Includes international cash ($197), cash to settle legacy matters including tax settlement ($200), AK Quality Bank judgment and other matters. 2

Debt Balance1 Scheduled Debt Retirements & Amortization (6) Debt Balance @ 6/30/05 7,744 7.5% Scheduled Debt Retirements & Amortization (23) Debt Balance @ 9/30/05 $7,721 7.5% Fixed Rate Debt @ 9/30/05 $7,073 7.7% Variable Rate Debt @ 9/30/05 $648 5.7% Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Consolidated Debt Balance @ 12/31/04 $7,962 7.4% Scheduled Debt Retirements & Amortization (216) Capitalized Lease 4 Debt Balance @ 3/31/05 7,750 7.4%

Business Unit Results

Exploration & Production Ralph Hill Senior Vice President

Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $159 $70 $381 $165 Nonrecurring: Ownership Issue - - - 11 Gain on sale of assets (22) - (29) - Recurring Segment Profit $137 $70 $352 $176 3Q04 to 3Q05 financial highlights include: Volume increase of 17% Net realized price increase of 44% Hedge ineffectiveness expense of $15.8MM in 3Q05 Recurring profit increase of 96%, excluding hedge ineffectiveness 119% Base business sequential quarter improved Increased recurring segment profit 16%, excluding hedge ineffectiveness 30% Increased volumes 5% $94 million negative hedge impact in 3Q05 including $16 million hedge ineffectiveness, $186 million year to date Exploration & Production

Strong Domestic Production Growth Exploration & Production 2004 2005

Impressive volume growth continues Full year with no lost time accidents for E&P Big George gross production up to 135 MMcf/d 12 rigs operating in Piceance Valley, 3 rigs in Highlands First H&P rig to be delivered in November Highlands production reaches 13 MMcf/d Additional Piceance Highland opportunity obtained Ft. Worth progressing Stable San Juan production continues International volumes up 10% sequentially Exploration & Production 3rd Quarter and 2005 Accomplishments

Powder River - Big George Coal Area Up 67 MMcf/d or 98% over a year ago Up 25 MMcf/d or 23% sequentially Big George production increase continues to offset Wyodak decline Exploration & Production Williams' Big George Production 0 20 40 60 80 100 120 140 160 Jun '04 Sep '04 Dec '04 Mar '05 Jun '05 Sep '05 MMcfd

Piceance Production Growth Up 84 MMcf/d or 34% over a year ago Up 19 MMcf/d or 6% sequentially Exploration & Production

3P Reserves August '05 Announcement: 37.5% increase in probable and possible reserves since year end '04 Extensive study of Piceance Valley yielded additional 1,600 locations and approximately 1.5 Tcf probable and possible reserves Rock quality Land/topography Drilling reach H&P rig capabilities provide access to some of the additional locations Does not include areas such as Trail Ridge, Ryan Gulch, Red Point and Allen Point Exploration & Production '04 YE Proved Existing Proved, Prob. & Poss. 3 Tcf 8.5 Tcf 3P '04 YE 7.0 Tcf '04 YE Proved

Piceance Highlands - Operations Update Exploration & Production

Project Area Net Acres Estimated Gross Potential Locations Estimated Net Potential Reserves (BCF) (1) 2004 Wells 2005 Wells 2006 Wells Trail Ridge (40-acre density)(2) 20,638 500 500 3 12 20 Ryan Gulch (40-acre density) 15,780 770 700 3 8 15 Allen Point (40-acre density) 6,240 200 140 0 6 9 Red Point (10-acre density) 1,908 190 200 0 2 10 Total 44,566 1,660 1,540 6 28 54 (1) Not included in US Reserves summary of 3.0 Tcf proved and 8.5 Tcf proved, probable and possible (2) 10-acre increased density hearing on COGCC docket for December 5, 2005 Piceance Highlands Projects Summary Exploration & Production

Piceance Highlands - Year to Date Results Exploration & Production Project Area Wells Drilled / Completed Average 30 Day Rate / Completed Well (MMCF/D) Preliminary Reserves Range (BCF/well) Trail Ridge 12 / 9 1.1 1.2 - 1.4 Ryan Gulch(1) 2 / 1 1.4 1.2 - 2.0 Red Point (2) - - 1.2 1.2 - 1.4 Allen Point 3 / 1 1.1 1.2 - 1.4 (1) Combination of our wells and offset wells from this year (2) All Rates and reserve range estimates based on offset areas

Reflective of core basins * Includes LOE, G&A, taxes and gathering ** Includes acquisition and development expenditures / proved reserves ('02-'04 average) Cash Margin Analysis Exploration & Production Previous 3-Year Average (2005-07) Cash Margin Cash Costs* Previous $1.81 $0.78 $3.71 $5.52 $0.00 $1.25 $2.50 $3.75 $5.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs** $4.56 $1.56 $3.00

Dollars in millions Exploration & Production 2005-2007 Guidance 295 - 335 365 - 415 410 - 485 520 - 595 595 - 720 605 - 680 760 - 860 735 - 885 625 - 700 740 - 840 850 - 950 645 - 750 815 - 930 960 - 1,135 Includes YTD nonrecurring adjustments which increase reported earnings by $29 million $8.70 is average for 2005 and includes a $13.31 estimate for the 4th quarter Note: If guidance has changed, previous guidance from 8/4/2005 is shown in italics directly below $6.34 $5.96 $5.75 2005 2006 2007 Segment profit $575 - 6001 $650 - 725 $775 - 900 Annual DD&A 235 - 265 335 - 375 425 - 475 Segment profit + DD&A $810 - 865 $985 - 1,100 $1,200 - 1,375 Capital spending $675 - 725 $950 - 1,050 $950 - 1,050 Production (MMcfe/d) 650 - 675 750 - 825 875 - 975 Unhedged Price Assumption (NYMEX, $/Mcf) $8.702 $8.50 $7.00 Hedge Volume (MMcfe/d) 383 414 287

Dollars in millions 2006-07 Guidance Reconciliation Exploration & Production

Strategy remains rapid development of our premier drilling inventory Delivering meaningful volume growth through expanded development drilling activity -- Piceance is primary growth driver Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Maintaining top quartile cost and efficiency position Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles New opportunities contributing Trail Ridge, Ryan Gulch, Red Point, Allen Point, Ft. Worth Basin, and Caney Shale Experienced and talented workforce Key Points Exploration & Production

Midstream Alan Armstrong Senior Vice President

Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $121 $105 $359 $314 Nonrecurring: Depreciable Life Adjustment - 6 6 Devils Tower Revenue Recognition1 - 17 - - Recurring Segment Profit $121 $128 $359 $320 Key Business Drivers: Higher Gathering and Processing Fee Revenue Outages in Gulf Coast Drove High Western Margins Total NGL Production Lowered by Outages Midstream 1 Recognition of revenue correction 2Q '04 to 3Q '04.

3rd Quarter and 2005 Highlights Rapidly responded to Katrina Providing industry solutions: Discovery open seasons Damaged by Rita Cameron Plant still down Max volume at Canada Won Tahiti Gulf of Mexico business Delivering promised expansions: Opal TXP 5 Blind Faith 3rd quarterly increase in west gathered volumes & revenues 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 2004 150 127 172 197 2005 175 155 170 0 Recurring Segment Profit + Depreciation Midstream

2005 2006 2007 Segment Profit $440-480 $400-500 $410-530 Annual DD&A 180-190 185-195 195-205 Segment Profit + DDA $620-670 $585-695 $605-735 Capital Spending $120-140 $230-250 $180-220 Note: If guidance has changed, previous guidance from 8/4/2005 is shown in italics directly below Midstream 2005-07 Guidance Dollars in millions $400 - $470 $580 - $660 $400 - $520 $110 - $130 $100 - $130 $590 - $720 $190 - $200 Major Growth Projects Update: In Guidance Identified '06-'07 Proposal Stage '06-'08 Opal TXP V (2Q 2007) $200-300 MM $600 MM Blind Faith (3Q 2007)

Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted margin. Midstream 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2004 Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Strong Free Cash Flow

Midstream Delivering Promised Expansions $177 MM to extend Canyon Chief and Mountaineer 37 miles Expected to be ready for service by 3Q 2007 Opportunity for gas processing at Mobile Bay Opportunity for gas transport through Transco and Gulfstream Liquids could be fractionated at Baton Rouge or Paradis Blind Faith

Midstream Delivering Promised Expansions Opal TXP V Adding capacity: Gas processing ~ 350 MMcf/day Liquids production ~ 17,000 BBls/day Total post-expansion capacity: Gas processing ~ 1.5 Bcf/day Liquids production ~ 68,000 BBls/day In service by 2Q 2007 Serving the Pinedale Anticline Field

Key Points Strong earnings and cash flows despite hurricanes MLP supplements growth strategy Capturing growth opportunities Delivered on "First Tranche" of expansion opportunities Organic growth around our Western assets Footprint expansion in the deepwater Robust opportunities in the pipeline Midstream Tutorial on November 30 Midstream

Gas Pipeline Phil Wright Senior Vice President

Segment Profit $161 $149 $493 $429 Nonrecurring 1999 Fuel Tracker adjustment1 (14) - (14) - Pension expense reduction1 - - (17) - Adjustment to carrying value of certain liabilities1 - - (18) - Write-off hydrostatic testing - - - 9 Recurring Segment Profit $147 $149 $444 $438 3Q04 to 3Q05 financial highlights include: $5 million increased earnings at Gulfstream $(5) million Gray's Harbor contract termination Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Gas Pipeline 1 Prior period items

Northwest's 26" Replacement receives final FERC approval Transco and Gulfstream remained operational and met market demands throughout hurricane season Successful Gulfstream financing Successful in accelerating growth across our pipelines: Gulfstream began new transportation service to Tampa Electric under new long-term firm service agreement for 48 Mdth/d Construction began in July and wrapping up for Central New Jersey expansion project Transco holds successful open season for the Potomac Expansion project in July NWP announced an open season on the Parachute Lateral Project (Oct.) Transco announced open season on the Sentinel Project (Nov.) 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 213 210 211.7 223.9 2005 220.7 208 214.1 0 Gas Pipeline 3rd Quarter and 2005 Accomplishments

2005 2006 2007 Segment Profit $630 - 6451 $485 - 5302,3 $585 - 655 Annual DD&A 270 - 280 290 - 300 300 - 310 Segment Profit + DDA $900 - 925 $760 - 815 $885 - 965 Capital Spending $390 - 420 $600 - 6803 $300 - 390 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 8/04/05 is shown in italics directly below Gas Pipeline Includes: YTD nonrecurring items which increase reported earnings by $49 million Includes: Pipeline Safety Costs of $31 million previously capitalized (see note 3) Higher interest expense of $20 million at Gulfstream as a result of the October $850 million financing No nonrecurring or one-time items Higher expenses than 2005 3 Impact of Pipeline Safety Improvement Act accounting rule reflected. Assumes $31 million of lower capital offset by $31 million of higher expenses. 590 - 615 860 - 895 600 - 700 500 - 565 790 - 865 250 - 325 370 - 420

2005-2007 Capital Spending Detail $300 - 390 $600 - 680 $390 - 420 Total 120 - 155 20 - 35 20 - 30 2 276 48 $180 - 235 $305 - 370 $325 - 335 Normal Maintenance/ Compliance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion1 Note: Sum of ranges may not add due to rounding Gas Pipeline 10 - 20 600 - 700 70 - 90 250 - 325 310 - 400 305 - 335 370 - 420 1Major Growth Projects (in guidance): 2005 2006 2007 Central New Jersey (in-service 11/05) $10 - 15 Leidy to Long Island (in-service 11/07) $ 5 - 10 $10 - 20 $75 - 95 Potomac Expansion (in-service 11/07) $ 5 - 10 $45 - 65

Key Points Strong performance continues; operationally and financially Strong cash flow provider Continued progress Compliance and reliability projects Expansion developments Preparation for rate cases on schedule to be in effect 2007 Gas Pipeline

Power Bill Hobbs Senior Vice President

Segment Profit Power Note: MTM Adjustments (recurring) excludes $12mm paid in 3Q05 for buyout of gas supply contract Dollars in millions 2005 2004 2005 2004 Gross Margin (Includes MTM) ($203) $131 ($98) $202 SG&A (21) (20) (54) (56) Operating & Other Inc./(Expense) (2) (2) (35) (25) Segment Profit/(Loss) (Includes MTM) (226) 109 (187) 121 MTM Adjustments 201 (142) 149 (87) Segment Profit/(Loss) After MTM Adjustments ($25) ($33) ($38) $34 Segment Profit/(Loss) (Includes MTM) ($226) $109 ($187) $121 Nonrecurring: Expense related to Settlements and Litigation Contingencies 0 0 13 0 Expense related to prior period 0 0 12 0 Recurring Segment Profit/(Loss) (226) 109 (162) 121 MTM Adjustments (recurring) 213 (142) 160 (87) Recurring Segment Profit/(Loss) After MTM Adjustments ($13) ($33) ($2) $34 3rd Qtr YTD

Power 1 Includes YTD nonrecurring adjustments which decrease reported Segment Profit by $25 million and reported Segment Profit after MTM Adjustments and CFFO by $37million. Power Segment Profit after MTM Adjustments and Power Segment Standalone CFFO would be $36 million higher on a recurring basis. 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. YTD - Segment Profit to Cash Flow Power and Dollars in Millions Natural Gas Other Total YTD Gross Margin ($98) ($98) SG&A & Other Inc/(Exp) (89) (89) Segment Profit/(Loss) 1 (187) 0 (187) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (101) (101) Add Realized Gains from MTM previously recognized 250 250 Segment Profit/(Loss) after MTM Adjustments 1 (38) 0 (38) Total Working Capital Change 0 82 82 Power Segment CFFO 1 (38) 82 44 Est. Working Capital Used for Other BU's 0 (39) (39) Power Segment Standalone CFFO ($38) $43 $5

Dollars in millions Items Impacting 3Q Performance Segment Profit After MTM Adjustments: Q305 Forecast (as of 6/30/05) $54 Estimated impact of mild weather in the West: (30) Cooling Degree Days (CDDs) at Los Angeles (LAX) YTD are 17% below 5 yr avg and 43% below '04 Average September peak load in Cal-ISO system 13% below 2004 Estimated impact of higher NG prices, hurricanes & others (25) Estimated impact of plant outages (12) Buyout of gas supply contract (12) ______ Q305 Segment Profit After MTM Adjustments ($25) Power

Cash Flow Analysis Power Undiscounted dollars in millions (GAAP Measure) Note: 3Q05 forecast estimated as of 12/30/04. 3Q05 actual cash flows agree in total with Power's Cash Flow Statement; however, the allocation of actual cash flows to the various deal types is based on estimates. Note: Estimated Cash Flows includes YTD nonrecurring adjustments which decrease reported cash flows by $36 million. Estimated cash flows would be $36million higher on a recurring basis. Combined Power Portfolio Actual v. Forecast 3Q'05 Q3'05A Q3'05F YTD05A YTD05F Tolling Demand Payment Obligations ($126) ($126) ($310) ($310) Resale of Tolling 34 14 116 87 Full Requirements (6) 0 (1) 6 Long-term Physical Forward Power Sales 3 10 46 54 OTC Hedges 13 4 89 74 Est. Tolling Cash Flows Associated with Hedges 117 165 Estimated Merchant Cash Flows 60 64 Subtotal Cash Flows 7 79 64 142 NG & Other Commodity (8) (6) (13) (7) SG&A and Other (24) (18) (89) (54) Working Capital & Other (15) (7) 82 83 Power segment CFFO (40) 48 44 164 Est. Working Capital Used for Other BU's 16 0 (39) 0 Power Standalone Cash Flows ($24) $48 $5 $164 88 123

2005 2006 2007 Prior Segment Profit Guidance ($50) - 50 ($270) - (120) ($220) - (70) MTM Earnings (3Q05) (141) Est. Forward MTM Impact 50 50 40 Chg due to Mkt Conditions, New deals & Other (108) 0 - (50) Total Impact (199) 50 - 0 40 Change in Segment Profit Guidance (200) 50 - 0 40 Segment Profit Guidance (225) - (175) (225) - (125) (180) - (30) Estimated MTM Adjustments 175 270 230 75 320 270 Reported Segment Profit after MTM Adj (50) - 0 50 - 150 50 - 200 25 - 125 50 - 200 Non-Recurring 25 0 0 Recurring Segment Profit after MTM Adj (25) - 25 50 - 150 50 - 200 50 - 150 50 - 200 50 - 150 50 - 200 Capital Expenditures - - - Dollars in millions 2005-07 Guidance Power Note: If guidance has changed, previous guidance from 2nd quarter is shown in italics directly below Cash Flow from Operations 25 - 75 50 - 150 0 - 200

New Power Contracts - 2005 Highlights Deals Consummated Around Each Toll All Customer Classes Have Been Represented Utilities Co-ops & Munis Hedge funds & banks Favorable Credit Terms Zero margining provisions in two deals in excess of 4 years Margin Caps in place for approx. 2000 MW of toll resell Lower margining agreements and netting will result in lower margin working capital Power

2005 Successes West 1,500 MW resale of tolling from AES 4000: 854 MW starting in 2006 and growing to 1,500 MW in 2007-10 490-MW resale of toll from AES 4000 for 2006-08 100-MW heat rate call option for 2008 690-MW capacity sales: from AES 4000 for June-Sept 2005 1,500 MW resale of tolling from AES 4000: 854 MW starting in 2006 and growing to 1,500 MW in 2007-10 Resale of tolling as a percentage of expected output: '06-67%, '07-85%, '08-81%, '09-68%, '10-68% Mid-Continent 500 MW heat rate-priced energy and capacity sale to CLECO utility starting in 2006- 09 (approval pending) 100 MW heat-rate call option for 5 years - 2009 (Kinder toll) 244-MW (max) block heat rate-priced energy sale for June-Sept 2005 Northeast 100-MW capacity sale from Ironwood to municipality for June 2005-May 2006 1,000 MW of heat-rate call options sold through 2006 Power

Dollars in millions 2005 Forecast: Recurring Segment Profit After MTM Adjustments Recurring Segment Profit After MTM Adjustments: 2005 Full Year Forecast $(25) - 25 Estimated cash flows from new hedges 50 - 60 Estimated improvement in weather 15 - 55 Reduced plant outages 10 - 10 _______ 2006 Full Year Forecast $50 - 150 Power

Key Points Results for 3rd quarter impacted by Mild weather in west Unplanned outage in east Hurricanes and high natural gas prices CFFO YTD positive Full year recurring segment profit guidance is at break even despite higher NG prices and weak market conditions. Deal flow has increased as previously shown. Power Tutorial on November 30 Power

2005-07 Consolidated Outlook Don Chappel CFO

Segment profit before MTM adjustment $1,375 - $1,525 $1,300 - $1,585 Net Interest Expense (650) - (670) (650) - (670) Other (Primarily General Corp. Costs) (70) - (100) (70) - (100) Pretax Income 655 - 755 580 - 815 Provision for Income Tax (260) - (300) (220) - (335) Income from Continuing Ops 395 - 455 360 - 480 Income/(Loss) from Discontinued Ops (10) - 0 (10) - 0 Net Income $385 - 455 $350 - 480 Diluted EPS $0.64 - $0.75 $0.58 - $0.79 Recurring Income from Cont. Ops $402 - $462 $377 - $497 Diluted EPS - Recurring $0.66 - $0.76 $0.62 - $0.82 Diluted EPS - Recurring After MTM Adjustments 1 $0.84 - $0.94 $0.70 - $0.90 Dollars in millions, except per-share amounts Nov 3 Guidance Consolidated 2005 Forecast Guidance Aug 4 Guidance 1 Includes MTM adjustment of $75 million (pretax) in Aug 4 guidance and $175 million (pretax) in Nov 3 guidance Note: Fully diluted shares of 605 million used in Aug 4 guidance and Nov 3 guidance

Dollars in millions 2005-07 Segment Profit Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total MTM Adjustment Total After MTM Adj. 2005 2006 Consolidated $575 - 600 440 - 480 630 - 645 (225) - (175) (45) - (25) $1,375 - 1,525 175 $1,550 - 1,700 $650 - 725 400 - 500 485 - 530 (225) - (125) (60) - (80) $1,250 - 1,550 270 $1,520 - 1,820 Note: If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below 2007 $775 - 900 410 - 530 585 - 655 (180) - (30) 10 - (30) $1,600 - 2,025 230 $1,830 - 2,255 410 - 485 520 - 595 595 - 720 400 - 470 590 - 615 (220) - (70) 1,300 - 1,585 75 320 270 1,375 - 1,660 1,515 - 1,815 1,640 - 2,065 1,195 - 1,495 1,370 - 1,795 (270) - (120) (50) - 50 500 - 565 400 - 520 45 - (45) (50) - (35)

2005 2006 2007 Exploration & Prod. $675 - 725 $950 - 1,050 $950 - 1,050 Midstream 120 - 140 230 - 250 180 - 220 Gas Pipeline 390 - 420 600 - 680 300 - 390 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,200 - 1,350 $1,825 - 2,050 $1,425 - 1,625 Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below Consolidated 2005-07 Capital Expenditures 605 - 680 760 - 860 735 - 885 700 1,100 - 1,300 1,525 - 1,750 250 - 325 110 - 130 100 - 130 1,100 - 1,300 370

1 Operating free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below Dollars in millions 2005-07 Outlook Consolidated Segment Profit Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Operating Free Cash Flow 1 2005 $1,375 - 1,525 1 175 1,550 - 1,700 700 - 775 1,325 - 1,525 1,200 - 1,350 125 - 175 2006 $1,250 - 1,550 270 1,520 - 1,820 790 - 890 1,625 - 1,925 1,825 - 2,050 (200) - (125) 2007 $1,600 - 2,025 230 1,830 - 2,255 900 - 1,000 1,850 - 2,150 1,425 - 1,625 425 - 525 1,300 - 1,585 75 320 270 1,375 - 1,660 1,515 - 1,815 1,640 - 2,065 1,195 - 1,495 1,370 - 1,795 50 - 150 25 - 100 1,150 - 1,450 1,650 - 1,950 1,100 - 1,300 1,525 - 1,750 1,100 - 1,300 550 - 650 840 - 940 770 - 870 1,550 - 1,850

Strong Operating Cash Flow Growth & Increasing Investment Opportunities . . . 2003 2004 2005 2006 2007 Cap Ex-Low 790 1200 1825 1425 Cap Ex-High 790 1350 2050 1625 CFFO-Low 588 1482 1325 1625 1850 CFFO-High 588 1473 1525 1925 2150 Debt to Cap 0.75 0.623 0.58 0.56 0.54 0.75 0.623 0.59 0.58 0.56 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,473 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% 56% to 58% 54% to 56% Consolidated 75% $588 $1,200 to $1,350 $1,425 to $1,625 $790 Cap Ex $1,850 to $2,150 Opportunity Rich Increasing Cash Flow $1,625 to $1,925 $1,825 to $2,050 Declining Debt / Cap % 58% to 59% $1,325 to $1,525

Segment Profit Guidance Trend 2004 2005 2006 2007 2008 SPAM Low 1263 1550 1520 1830 2050 SPAM High 1263 1700 1820 2255 2600 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1175 1825 1450 Cap Ex-High 790 1350 2050 1650 $ Millions $1,550 to $1,700 $1,520 to $1,820 $1,830 to $2,255 $1,263 (recurring) 1 Includes MTM adjustments of ($118) in 2004, $175 in 2005, $270 in 2006, $230 in 2007, and $167 in 2008. Consolidated Segment Profit After MTM Adjustments 1 (1-Yr CAGR) 17.4% 15.0% 28.7% (2-Yr CAGR) (3-Yr CAGR) $2,050 to $2,600 16.5% (4-Yr CAGR)

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 Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA-adding opportunities may require new capital If new capital is needed, choose optimal sources of capital Combination of growth in operating cash flows and EVA drives value creation Financial Strategy/Key Points Consolidated

Summary Steve Malcolm Chairman, President & CEO

Key Points Current growth activity continues to move key performance measures up Investing in future growth First planned sale to Williams Partners to deliver growth capital while retaining asset control Scope, scale of growth opportunities continues to expand Raising earnings, cash guidance; expect upward trend to make sharper incline in 2008 Summary

Q&A

Non-GAAP Reconciliations

Non-GAAP Disclaimer This presentation includes certain financial measures, EBITDA, recurring earnings, free cash flow and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. EBITDA represents the sum of net income (loss), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Recurring earnings and recurring segment profit provide investors meaningful insight into the Company's results from ongoing operations. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Company's assets and the cash that the business is generating. Neither EBITDA nor recurring earnings and recurring segment profit are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. Certain financial information in this presentation is also shown including Power mark-to-market adjustments. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Previously the Company did not qualify for hedge accounting with respect to its Power segment as a result of the Company's stated intent to exit the Power business. The Company ceased efforts to market the sale of Power during the third quarter 2004, and now qualifies for hedge accounting. Hedge accounting reduces earnings volatility associated with Power's portfolio of certain derivative hedging instruments. Prior to the adoption of hedge accounting, these derivative hedging instruments were accounted for on a mark-to-market basis with the change in fair value recognized in earnings each period. Management uses the mark-to-market adjustments to better reflect Power's results on a basis that is more consistent with Power's portfolio cash flows and to aid investor understanding. The adjustments reverse forward unrealized mark-to- market gains or losses from derivatives and add realized gains or losses from derivatives for which mark-to-market income has been previously recognized, with the effect that the resulting adjusted segment profit is presented as if mark-to-market accounting had never been applied to designated hedges or other derivatives. The measure is limited by the fact that it does not reflect potential unrealized future losses or gains on derivative contracts. However, management compensates for this limitation since reported earnings do reflect unrealized gains and losses of derivative contracts. Overall, management believes the mark-to-market adjustments provide an alternative measure that more closely matches realized cash flows for the Power segment.

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

EBITDA Reconciliation 190 DD&A (3) Provision (benefit) for Income Taxes 164 Net Interest Expense $4 Net Income $356 EBITDA 1 Loss from Disc. Operations Non-GAAP Reconciliation 3Q05 Dollars in millions YTD $247 2 491 546 169 $1,455

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 3Q 2005 Segment Contribution Non-GAAP Reconciliation

Net Income $385 - 455 $350 - 480 Income from Disc. Ops. 10 - 0 10 - 0 Net Interest 650 - 670 650 - 670 DD&A 700 - 775 700 - 775 Provision for Income Taxes 260 - 300 220 - 335 Other/Rounding (5) - 0 (5) EBITDA $2,000 - 2,200 $1,930 - 2,260 MTM Adjustments 175 75 EBITDA - after MTM Adj. $2,175 - 2,375 $2,005 - 2,335 Dollars in millions 2005 Forecast EBITDA Reconciliation Consolidated Nov 3 Guidance Aug 4 Guidance

Power 1 (225) - (175) 10 - 20 (215) - (155) Gas Pipeline 630 - 645 270 - 280 900 - 925 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) Rounding TOTAL E&P 575 - 600 235 - 265 810 - 865 Midstream 440 - 480 180 - 190 620 - 670 Total * 1,375 - 1,525 700 - 775 2,075 - 2,300 (70) - (100) (5) - 0 2,000 - 2,200 Corp/ Other (45) - (25) 5 - 20 (40) - (5) 2005 Forecast Segment Contribution Non-GAAP Reconciliation Dollars in millions 1 Segment Profit is prior to MTM adjustments

Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. Reported Consolidated $575 - 600 440 - 480 630 - 645 (225) - (175) (45) - (25) $1,375 - 1,525 175 $1,550 - 1,700 YTD Non-Recurring ($29) - - (49) 25 53 $0 - - $0 Recurring $546 - 571 440 - 480 581 - 596 (200) - (150) 8 - 28 $1,375 - 1,525 175 $1,550 - 1,700 Power After MTM Adj. ($50) - 0 1 $25 ($25) - 25 2005 Segment Profit - Recurring 1 Includes reported results and mark-to-market as indicated above

Net Income $385 - 455 $350 - 480 Less: Discontinued Operations 10 - 0 10 - 0 Income from Continuing Ops $395 - 455 $360 - 480 Non-Recurring Items (Pretax) 7 23 Less / (Plus) Taxes @ Approx. 39% 0 (6) Non-Recurring After Tax 7 17 Recurring Income from Cont. Ops $402 - 462 $377 - 497 Recurring EPS $0.66 - $0.76 $0.62 - $0.82 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Inc. from Cont. Ops after MTM Adj. Inc. from Cont. Ops after MTM Adj. EPS 175 (68) 107 $509 - 569 $0.84 - $0.94 75 (29) 46 $423 - 543 $0.70 - $0.90 2005 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts Nov 3 Guidance Aug 4 Guidance

Dollars in millions 2005-07 Guidance Reconciliation Consolidated CAP EX: Aug. 4 Guidance E&P: Incremental Drilling & costs Midstream: Expansion (Opal & Blind Faith) Gas Pipes: Expansions Other Misc / Rounding Nov. 3 Guidance 2005 $1,100 - 1,300 60 - - - - 40 - (10) $1,200 - 1,350 2006 $1,525 - 1,750 190 120 10 (20) $1,825 - 2,050 2007 $1,100 - 1,300 190 85 60 (10) $1,425 - 1,625 SEGMENT PROFIT 1 Aug. 4 Guidance - Reported E&P: Price, cost & volume Increases Midstream: Margin Increases " Expansions Gas Pipes: Lower Expenses 25, NonRecurring/Other 10 " Accounting Change (30), Lower Expenses 15 Power: High Gas Prices / Weather in West Other Misc / Rounding Nov. 3 Guidance - Reported $1,375 - 1,660 140 25 - - 35 - - (100) 75 - (60) $1,550 - 1,700 $1,515 - 1,815 130 - - - - - - (15) - - (110) $1,520 - 1,820 $1,640 - 2,065 180 - - 10 - - - - - - - - $1,830 - 2,255 1 Segment Profit After MTM Adjustment

Dollars in millions 2005- 07 Guidance Reconciliation Consolidated CASH FLOW FROM OPERATIONS (CFFO): Aug. 4 Guidance E&P Seg Profit / DD&A Increases Midstream Segment Profit Increase Gas Pipes Segment Profit Changes Power Change in CFFO Guidance Other Increases / (Decreases) Nov. 3 Guidance 2005 $1,150 - 1,450 140 25 35 (25) - (75) 0 - (50) $1,325 - 1,525 2006 $1,550 - 1,850 140 - - (15) (25) (25) $1,625 - 1,925 2007 $1,650 - 1,950 220 10 - - - - (30) $1,850 - 2,150

Appendix

Consolidated EPS $0.34 $0.07 $0.01 - $0.42 Recurring EPS 0.33 0.11 ($0.01) - 0.44 Rec. EPS after MTM Adj. 0.22 0.16 0.22 - 0.60 Average Shares (MM) 599 579 581 - 605 2005 1Q 2Q 3Q 4Q Total EPS $0.02 ($0.03) $0.19 $0.13 $0.31 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS Metrics

Interest on Long-Term Debt $575 - 583 Amortization Discount/Premium and other Debt Expense 25 - 27 Credit Facilities: (incl. Commitment Fees plus LC Usage) 32 - 40 Interest on other Liabilities 23 - 30 Interest Expense $655 - 680 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $650 - 670 Dollars in millions 2005 Consolidated 2005 Interest Expense Guidance

2005 Effective Tax Rates Consolidated

Dollars in millions Exploration & Production 2005-2007 Hedge Update 1 Please note basin locations not NYMEX 2005 2006 2007 Fixed Price: 4th Qtr NYMEX Volume (MMcfe/d) 283 299 172 Price ($/Mcfe) $4.49 $4.39 $4.18 Collars : NYMEX Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 $6.62 - $8.42 $6.50 - $8.25 Regional NWPL Rockies1 Volume (MMcfe/d) 50 50 50 Price ($/Mcfe) $6.10 - $7.70 $6.05 - $7.90 $5.65 - $7.45 EPNG San Juan1 Volume (MMcfe/d) 50 Price ($/Mcfe) $5.65 - $7.45

3Q 2005 Net Realized Price Calculation Exploration & Production

2005 4th Quarter Price Modeling Unhedged Price (NYMEX) $8.70 $8.50 $7.00 2005 2006 2007 Note: Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes Exploration & Production 2005 Unhedged Hedge Market Price: NYMEX $13.00 - $13.60 $4.49 Basis Differential (3.00 - 3.60) (0.47) Net basin market price $9.40 - $10.60 $4.02 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $8.40 - $9.80 $3.02 - $3.22 Year Volume Totals (Bcfe) (total daily vols (daily hedge - - daily hedge vols) volumes) x x (92/1000) (92/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price)

Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2000-2004. Midstream Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin

Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 733 763 846 Commodity 301 255 215 212 Note: Total revenues less cost of goods sold. Reflects forecasted margins in 2006-2007 at mid- point of range. Midstream 30% 70% 26% 22% 20% 74% 78% 80%

Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted average margin. Midstream 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2004 Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Strong Free Cash Flow Still Updating This Slide

Gas Pipeline Dollars in millions Strong Free Cash Flow 2003 2004 2005 2006 2007 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion Maintenance Mandatory Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2005 - 2007.

Corp./ E&P Midstream Power Other Total Dollars in millions As of 9/30/05 *Note: The allocation of LC's between business units as of 3/31 has been adjusted from that previously reported. Total 3/31/05 LC's reported is unchanged. 1Reflects net amount of margins out less margins in. WMB Collateral Outstanding $2 $0 $51 $0 $53 $0 $1 $24 $0 $25 $2 $1 $75 $0 $78 $1,145 $224 $247 $91 $1,707 $1,147 $225 $322 $91 $1,785 $475 $184 $357 $92 $1,108 $581 $116 ($49) $1 $649 Margins & Ad. Assurances1 Prepayments Subtotal Letters of Credit Total as of 9/30/05 Total as of 06/30/05 Change

Dollars in millions WMB Collateral Sensitivity Margin volatility (1% chance of exceeding) - - Potential incremental collateral requirement 9/30/05 6/30/05 3/31/05 30 days ($469) ($178) ($124) 180 days ($868) ($458) ($328) 360 days ($926) ($351) ($341) Increased margin volatility results from high natural gas prices and volatility Assumption: The margin numbers above consist of only the forward marginable position values, starting from November 2005.

Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads, for all Williams business units combined. 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). Price Increase 2005 2006 2007 WMB Natural Gas (Per MMBtu) $0.10 $0-$2 $4-$6 $12-15 1 Power West Spark Spread Power Price (Per MWh) $5.00 $0-5 $5-15 $5-15 2 Midstream Processing Margin NGL Price (Per Gallon) $0.01 $5-10 $10-15 $10-15 3 Estimated dollars in millions

Types of Sales Around Tolling Deals - -Generally, from the most to least effective hedges Type of Sale Resale of tolling Heat-rate Sales Full requirements Capacity sales Forward fixed price sales How It Works Williams buys tolling rights for a certain dollar amount per kilowatt-year and: Sells the same or similar tolling rights to another party. Example: CDWR Product D. Sells call rights on energy, or fixed amounts of energy, at a price determined by a heat rate and fuel price. Serves the load (demand) of an entity often at a fixed price, utilizing production from other Williams assets and/or the entity's resources. Examples: EMC and Allegheny Co-op contracts. Sells the right to claim the generation as capacity. Some energy rights are usually associated. Sells fixed blocks of power at a specified price, usually w/o specifying a source. Example: CDWR ABC.

The Williams Companies, Inc. (WMB) 8-KWilliams Reports Third-Quarter 2005 Financial Results