The Williams Companies, Inc. (WMB) 8-K Williams Reports Fourth-Quarter and Full-Year 2005 Financial Results

Williams 2005 4th Quarter Earnings February 28, 2006 Exhibit 99.2

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.

2005 Review Steve Malcolm Chairman, President & CEO

2005 Headlines Key earnings measure more than doubles Generated $1.45 billion net cash from operations Production increases dramatically Took steps to accelerate reserves development Successful launch of master limited partnership Significant progress in resolving legacy issues Overview

What you'll hear about 2005 E&P growing - production, reserves, profits Recurring results up 122% U.S. production up 18% -- mostly via drill bit 277% reserves replacement with >99% success rate Total proved reserves 3.6 Tcfe Piceance Highlands shows promise Midstream sustains '04 record high; gears up for more growth Strength in the face of two hurricanes Brings new deepwater volumes on line Commits to expand capacity in Rockies Gas Pipeline customer demand supports growth Growth strengthens competitive position Sets delivery record again Rate case preparation begins Power reduces risk Executes additional mid-term deals Generates positive cash flow Overview

What you'll hear about 2006 and beyond Overview Expect to grow key earnings measure over 3-year horizon Opportunity rich Significant reserves for development Sizable growth projects in gathering and processing Stable of expansions that strengthen gas pipelines' competitive position Demand growth in key areas should drive more hedging of power portfolio Investing in value growth Committed more than $5 billion in capital projects Weighting capital toward E&P Opportunities expected to add CapEx for Midstream Expect to increase segment profit nearly 50% by 2008 Continued improvement in debt-to-cap ratio

Financial Results and 2006 Outlook Don Chappel CFO

Financial Results Dollars in millions (except per share amounts) 4th Qtr Year 2005 2004 2005 2004 Income from Continuing Operations $69 $95 $318 $93 Income (Loss) from Discontinued Operations - (22) (2) 71 Cumulative effect of change in accounting principle (2) - (2) - Net Income $67 $73 $314 $164 Net Income/Share $0.11 $0.13 $0.53 $0.31 Recurring Income from Cont. Ops./Share $0.28 $0.12 $0.72 $0.49 Recurring Income from Continuing Operations After MTM Adjustments/Share $0.26 $0.09 $0.86 $0.35 Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' website at www.williams.com and at the end of this presentation.

Recurring Income from Continuing Operations 4th Qtr Year 2005 2004 2005 2004 Income from Continuing Operations $69 $95 $318 $93 Nonrecurring Items Accrual for Regulatory & Litigation Contingencies/Settlements 78 - 96 - Impairments/Losses/Write-offs 61 31 119 70 Expense related to prior periods 28 4 - 15 Gain on Sale of Assets (9) (10) (47) (10) Debt Retirement Expense - 30 - 282 Insurance Arbitration Award - (103) - (103) Other - Net 9 4 12 18 Total nonrecurring 167 (44) 180 272 Tax Effect of Adjustments 48 (17) 50 104 Adjustment for nonrecurring excess deferred tax benefit (20) - (20) - Recurring Income from Continuing Operations Available to Common $168 $68 $428 $261 Recurring Income from Continuing Operations/Share $0.28 $0.12 $0.72 $0.49 Consolidated A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations is available on Williams' website at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts)

4th Qtr Year 2005 2004 2005 2004 Recurring Income from Continuing 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' website at www.williams.com. Dollars in millions( except per share amounts) Recurring Income from Continuing Ops. Available to Common $168 $68 $428 $261 Recurring Diluted Earnings per Common Share $0.28 $0.12 $0.72 $0.49 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains) losses (70) (23) (172) (304) Add realized gains from MTM previously recognized 48 (6) 310 186 Total MTM adjustments (22) (29) 138 (118) Tax Effect of Total MTM Adjustments (8) (11) 53 (46) After-tax MTM Adjustments (14) (17) 85 (72) Recurring income from Continuing Operations Avail. To Common Shareholders After MTM Adjustments $154 $51 $513 $190 Recurring Diluted Earnings Per Share After MTM adjustments $0.26 $0.09 $0.86 $0.35 Consolidated

Liquidity at Year-End 2005 Consolidated Dollars in millions Cash and cash equivalents 1,597 $ Other current securities 123 Less: Subsidiary & international cash Customer margin deposits payable $ 240 321 (561) Available unrestricted cash 1,159 Available revolver capacity 961 Total Liquidity 2,120 $

Business Unit Results

Exploration & Production Ralph Hill Senior Vice President

Dollars in millions 4th Qtr Year 2005 2004 2005 2004 Segment Profit $206 $71 $587 $236 Nonrecurring: Ownership Issue - 4 - 15 Gain on sale of assets - - (29) - Recurring Segment Profit $206 $75 $558 $251 4Q04 to 4Q05 financial highlights include: Volume increase of 14% Domestic net realized price increase of 79% Recurring segment profit increase of 175% $173 million negative hedge impact in 4Q05, $359 million year to date Exploration & Production Segment Profit

Strong Domestic Production Growth of 18% Exploration & Production 2005 Domestic production grew 18% or 93 MMcfe/d over 2004 15 - 20% production growth projected for 2006

Exploration & Production 2005 Accomplishments and Current Update Impressive domestic volume growth of 18% Domestic reserves replacement of 277% Successfully recruited talent, increased staff 34% Big George production continues to climb 2 rigs operating in Barnett Shale Mature San Juan basin production increased 4% Record International profit fueled by 8% volume increase and crude price 19 rigs operating in Piceance as of February 2006 2nd H&P rig on site Piceance Highlands production reaches 18 MMcfe/d

Powder River - Big George Coal Area Up 74 MMcfe/d or 101% over a year ago Up 11 MMcfe/d or 9% sequentially Big George production is driving basin growth Exploration & Production Williams' Big George Gross Production 0 20 40 60 80 100 120 140 160 Jun '04 Sep '04 Dec '04 Mar '05 Jun '05 Sep '05 Dec '05 MMcfe/d

Piceance Production Growth Up 88 MMcfe/d or 34% over a year ago Up 17 MMcfe/d or 5% sequentially Exploration & Production Williams' Piceance Net Production 150 200 250 300 350 2Q '04 3Q '04 4Q '04 1Q '05 2Q '05 3Q '05 4Q '05 MMcfe/d

An Industry Leader in 2005 Cost Performance Lease operating expense of $0.36 / Mcfe 3-year average F&D cost of $0.92 / Mcfe G&A cost of $0.34 / Mcfe Exploration & Production

Strong 2005 Reserves Performance Exploration & Production Total proved reserves 3.6 Tcfe Domestic proved reserves up 13.3% to 3.4 Tcfe 277% domestic reserves replacement 99% success rate Moved 603 Bcfe to proved Transfers of Probable to Proved Reserves (Bcfe) 2003 2004 Total Total for retained basins 408 451 1,462 2005 603

Exploration & Production Domestic Proved Reserves Reconciliation - -224 - -11 +603 +23 - -191 +451 Prod. +28 Prod. Acq. Sold YE 2003 Adds/ Rev. Acq. Adds/ Rev. YE 2005 YE 2004

Project Area Net Acres Estimated Gross Potential Locations Estimated Net Potential Reserves (Bcfe) 2004 Wells 2005 Wells Projected 2006 Wells Trail Ridge (10-acre density) 21,112 1,500 1,500 - 2,000 3 12 20 Ryan Gulch (40-acre density) 16,078 800 700 3 5 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 45,338 2,690 2,540 - 3,040 6 25 54 Piceance Highlands Projects Summary Exploration & Production

Piceance Highlands - Results To Date Exploration & Production Project Area Wells Drilled Average 30 Day Rate / Completed Well (MMcfe/d) Expected EUR* Range (Bcfe/well) Trail Ridge 15 1.1 1.2 - 1.6 Ryan Gulch 8 1.2 1.2 - 2.0 Allen Point 6 1.1 1.2 - 1.6 Red Point 2 1.2 1.2 - 1.4 * Estimated Ultimate Recovery

New E&P Opportunities Piceance Basin: Shale Ridge Prospect (Dakota Sandstone play) Leased 13,904 gross/net acres 100% WI; 87.5% NRI 10-year lease term Piceance Basin: Pending Williams Fork Project 2006 drill-to-earn commitment 11,000 net acres Uinta Basin: Sterling Hollow Prospect (Mesaverde tight gas sands play) Leased 39,911 contiguous gross/net acres 100% WI; 87.5% NRI 10-year lease term Paradox Basin: Resource Play (Ismay Group shales and tight gas sandstones) Leased 30,608 gross/net acres 100% WI; 87.5% NRI 5-year and 10-year terms on leases Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING Exploration & Production

Williams is a Leader in US Gas Production Growth through the Drill Bit Exploration & Production (1) US production given on a natural gas equivalent basis, natural gas only production not available. Source: Publicly reported data from EvaluateEnergy.com, press releases, and company websites

Reflective of core basins $5.75 is after hedging and includes average basin market price of $6.75 before hedging Cash costs include LOE, G&A, taxes and gathering F&D costs include acquisition and development expenditures/proved reserves ('03-'05 average) Cash Margin Analysis Exploration & Production 3-Year Average (2006-08) $0.81 Previous $0.92 Previous $5.52 $5.75 Cash Margin Cash Costs Previous $1.81 $3.71 $1.77 $3.98 $0.00 $1.25 $2.50 $3.75 $5.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs

2006 2007 2008 Segment profit $650 - 725 $775 - 900 $950 - 1,100 Annual DD&A 335 - 375 425 - 475 475 - 525 Segment profit + DD&A $985 - 1,100 $1,200 - 1,375 $1,425 - 1,625 Capital spending $950 - 1,050 $950 - 1,050 $1,000 - 1,150 Production (MMcfe/d) 750 - 825 875 - 975 950 - 1,100 Unhedged Price Assumption, ($/Mcf) NYMEX $8.50 $7.00 $7.00 Average San Juan/Rockies Price $7.32 $6.09 $6.10 Dollars in millions (except price assumptions) Exploration & Production 2006-08 Guidance Note: 2006-08 hedge information included in Appendix Note: If guidance has changed, previous guidance from 11/3/2005 is shown in italics directly below

An industry leader in production growth, cost efficiencies and reserves replacement Diligently managing increasing industry costs 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 Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles New opportunities contributing Experienced and talented work force Key Points Exploration & Production

Midstream Alan Armstrong Senior Vice President

Segment Profit Midstream Dollars in millions 4th Qtr Year 2005 2004 2005 2004 Segment Profit $112 $236 $471 $550 Nonrecurring: Depreciable Life Adjustment - 1 - 7 Gain on Asset Sales - (9) - (9) Insurance Arbitration Award - (94) - (94) Impairments - 17 - 17 Recurring Segment Profit $112 $151 $471 $471 4Q04 to 4Q05 financial highlights include: Significantly lower per unit NGL frac spreads Lower operating expenses Increased G&P fee revenue

4th Quarter and 2005 Highlights 2005 Opal TXP-5 construction commenced Construction of Tahiti and Blind Faith deepwater projects commenced Williams Partners L.P. (WPZ) successfully launched Hurricanes met with energetic response Sold $68MM in assets 4th Quarter Goldfinger and Triton production flowing on Devils Tower Significant progress on Overland Pass Pipeline project Opal TXP-4 acquisition 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 150 127 172 198 2005 175 155 170 162 Recurring Segment Profit + Depreciation Midstream

Note: If guidance has changed, previous guidance from 11/3/2005 is shown in italics directly below Midstream Dollars in millions 2006 2007 2008 Segment Profit $400-500 $410-530 $440-580 Annual DD&A 190-200 200-210 210-220 Segment Profit + DDA $590-700 $610-740 $650-800 Capital Spending $280-300 $230-270 $70-90 230-250 180-220 585-695 590-720 2006-08 Guidance 185-195 195-205 Major Growth Projects included in Guidance ($ Millions): Project Name - In Service Date 2006 2007 2008 Opal TXP IV (1Q 2006) $30 - - Opal TXP V (2Q 2007) 50 $15 - Blind Faith (3Q 2007) 90 85 - Wamsutter Phase II (4Q 2007) 10 65 - 1 1

Significant Progress Made on Growth Projects Western Deepwater 38 62 Western G&P Expansions Deepwater Expansions Devel. /Proposal Stage 2006 2007 2008 Spending $200MM - 400MM 40% 60% Western G&P Expansions ($75MM in guidance) Overland Pass Deepwater Expansions ($30MM in guidance) Under Negotiation 2006 2007 2008 Spending $700MM- 900MM Overland Pass Western Deepwater 30 10 60 60% 30% Opal Blind Faith 36 64 Blind Faith Opal TXP-V Opal TXP-IV Contracted/Approved 2006 2007 2008 Spending $280MM 65% 35% Midstream 10% In Guidance Not in Guidance

Overland Pass Pipeline Proposal Midstream Expected NGL Production End of Year 2008: Opal Processing Plant 65-70 MBPD Echo Springs Processing Plant 40-45 MBPD

Key Points Midstream Another record year despite hurricanes and lower commodity margins Continued to generate excess free cash Operating Cash Flow MLP Proceeds Asset sales Geographic diversification of processing assets mitigated decline in Mt. Belvieu frac spreads Significant progress on growth projects

Gas Pipeline Phil Wright Senior Vice President

Segment Profit Gas Pipeline Dollars in millions 4th Qtr Year 2005 2004 2005 2004 Segment Profit $93 $157 $586 $586 Nonrecurring: (Income)/expense related to prior periods 27 - (8) - Accrual of contingent refund obligation 10 - 10 - 1999 Fuel Tracker adjustment - - (14) - Write-off hydrostatic testing - - - 9 Recurring Segment Profit $130 $157 $574 $595 4Q04 to 4Q05 financial highlights include: Termination of Gray's Harbor contract - $5MM Higher fuel and operating expenses - $10MM

Transco: Central New Jersey project placed in-service 105 MDth/d of firm transportation serving the northeast market Successful open season for Sentinel to serve northeast market Precedent agreements signed for Potomac Expansion FERC certificate application filed for Leidy to Long Island Northwest: Successful open season for Parachute FERC certificate application filed in Jan 2006 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 213 210 211.7 223.9 2005 220.7 208 214.1 198 Gas Pipeline 4th Quarter and 2005 Accomplishments

2006 2007 2008 Segment Profit $475 - 5201 $585 - 655 $590 - 665 Annual DD&A 280 - 300 290 - 310 295 - 315 Segment Profit + DDA $755 - 820 $875 - 965 $885 - 980 Capital Spending $710 - 785 $390 - 490 $410 - 510 775 - 830 Dollars in millions 2006-08 Guidance Note: If guidance has changed, previous guidance from 11/03/05 is shown in italics directly below Gas Pipeline Includes: Pipeline safety costs of approximately $27 million to $35 million due to new accounting rule that requires certain pipeline assessment costs that have historically been capitalized to be recorded as expense beginning in 2006 Higher interest expense of $20 million at Gulfstream as a result of the October 2005 $850 million financing 600 - 680 290 - 300 300 - 310 300 - 390 885 - 965 485 - 530 1

2006-07 Capital Spending Detail $410 - 510 $390 - 490 $710 - 785 Total 230 - 250 180 - 220 95 - 105 - - 2 276 $180 - 260 $210 - 265 $340 - 405 Normal Maintenance/ Compliance 2008 2007 2006 Dollars in millions NWP 26" Replacement Expansion1 Note: - - Sum of ranges may not add due to rounding - - Ranges excludes AFUDC Gas Pipeline 20 - 35 305 - 370 600 - 680 1Major Growth Projects (in guidance): 2006 2007 2008 1st full yr Seg. Profit Parachute (In Service 1/07) $50 - 60 $8 Leidy to Long Island (In Service11/07) 10 - 15 $85 - 100 $1 - 5 18 Potomac (In Service 11/07) 5 - 10 55 - 65 1 - 5 11 Sentinel (In Service 11/08) 10 - 15 35 - 45 195 - 205 41 Greasewood (In Service 11/08) 25 - 30 2 - 4 180 - 235 300 - 390 120 - 155 Note: If guidance has changed, previous guidance from 11/03/05 is shown in italics directly below

Sentinel Nov 2008 Growth Projects and Opportunities Gulfstream Mainline Jan 2009 Leidy to Long Island Nov 2007 Potomac Nov 2007 Parachute Jan 2007 Pacific Connector Pipeline Late 2010 Prod. Area Mainline Exp Nov 2008 Mobile Bay South Summer 2008 Gas Pipeline Greasewood Nov 2008 Projects in proposal stage and not included in capital guidance Jackson Prairie Nov 2008

Key Points 2005 another strong year Strong cash flow provider Operational excellence Achieved new delivery records Met customer demand through hurricane challenges Customer focused Meeting market demands with new growth projects High rankings in customer satisfaction survey 2006 & forward Anticipate additional new growth projects Rate Case filings Gas Pipeline

Power Bill Hobbs Senior Vice President

Segment Profit/(Loss) Power Dollars in millions Segment Profit/(Loss) Before MTM Adjustment ($69) ($44) ($257) $77 Nonrecurring: Accrual for Regulatory & Litigation Contingencies/Settlements 69 - 87 - Impairments, Losses, Write-offs 23 - 23 - Expense Related to Prior Periods - - 7 - Recurring Segment Profit/(Loss) 22 (44) (140) 77 MTM Adjustment (Recurring) (22) (29) 138 (118) Recurring Segment (Loss) After MTM Adjustment - ($73) ($2) ($41) 4th Qtr Year 2005 2004 2005 2004 Note: MTM Adjustments (recurring) excludes $12mm paid in 3Q05 for buyout of gas supply contract Note: Might not sum due to rounding

Power 2005 - Segment Profit/(Loss) to Cash Flow From Operations 1 Includes nonrecurring adjustments which decrease reported Segment Loss by $117 million, $110 million of which is included in the "Working Capital/Other" column. 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. 2 Includes $12 million of nonrecurring loss from MTM Previously Recognized. Recurring MTM Adjustment is $138 million. 3 Recurring Segment Profit/(Loss) After MTM is ($2)mm. Commodity Working Power & NG Capital/Other 2005 1 ($147) ($110) ($257) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (172) (172) Add Realized Gains from MTM Previously Recognized 2 298 298 Segment Profit/(Loss) after MTM Adjustments 3 (21) (110) (131) Total Working Capital Change 0 319 319 Power Segment CFFO (21) 209 188 Est. Working Capital Used for Other Business Units 0 (61) (61) Power Segment Standalone CFFO ($21) $148 $127 Dollars in millions Segment Profit/(Loss) Before MTM Adjustments

2006-08 Guidance Power Note: If guidance has changed, previous guidance from11/03/05 is shown in italics directly below 1 2006-2008 CFFO guidance assumes no changes in Working Capital. Changes in Working Capital are likely if future commodity prices are volatile or if counterparties exchange Letters of Credit for cash held by WMB. Payment of regulatory and litigation/settlement accruals are not included in CFFO guidance.

2005 Contracts Power Reducing Risk and Increasing Cash flow Certainty

2006 Contracts Power Reducing Risk and Increasing Cash flow Certainty

Capacity Sold by Year Power *Note: 2005A based on hedged position @ 3/31/05 Tutorial Schedules. 3,078 4,734 4,326 4,241 3,117 3,032 2,624 4,287 0 2,000 4,000 6,000 8,000 2005A* 2006F 2007F 2008F Total Capacity Sold Remaining Available Upside

Cash Flow Analysis Power Estimated undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. 4 Working Capital & Other changes are zero in future years, as they are not reasonably estimable. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Actual Cash Flows for 2005 includes impact of certain nonrecurring items. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

Dollars in millions 2006 Forecast: Recurring Segment Profit/(Loss) After MTM Adjustments 2005 Recurring Segment Loss After MTM Adjustments $ (2) - (2) Estimated cash flows from new contracts executed in 2005 40 - 50 Current and forecasted improvement in markets 0 - 70 No unplanned plant outages & hurricanes forecasted 10 - 20 Other 2 - 12 _______ 2006 Estimated Segment Profit After MTM Adjustments $50 - 150 Power

Key Points Positive CFFO for Power Segment and Power Standalone in 2005 Recurring 2005 Segment Loss after MTM improves $39 million over 2004 levels despite record high gas prices, mild weather, hurricanes and unplanned outages Outlook for 2006 improves based upon strength of new contracts and improving market conditions Power remains focused on creating additional cash flow certainty, generating EVA and reducing risk in our portfolio Continued success closing new risk-reducing contracts Power

2006-08 Consolidated Outlook Don Chappel CFO

Segment profit before MTM adjustment $1,240 - $1,580 Net Interest Expense (665) - (705) Other (Primarily General Corp. Costs) (90) - (120) Pretax Income 485 - 755 Provision for Income Tax (200) - (315) Income from Continuing Ops 285 - 440 Income/(Loss) from Discontinued Ops (5) - 0 Net Income $280 - 440 Diluted EPS $0.46 - $0.72 Recurring Income from Cont. Ops $303 - $458 Diluted EPS - Recurring $0.50 - $0.75 Diluted EPS - Recurring After MTM Adj. 1 $0.78 - $1.03 Dollars in millions, except per-share amounts 2006 Consolidated 2006 Forecast Guidance 1 Includes MTM adjustment of $280 million (pretax) Note: Fully diluted shares of 610 million

Dollars in millions 2006-08 Segment Profit After MTM Adj. Exploration & Production Midstream Gas Pipeline Power 1 Other / Corp. / Rounding Total 2006 2007 Consolidated $650 - 725 400 - 500 475 - 520 50 - 150 (55) - (35) $1,520 - 1,860 2008 $775 - 900 410 - 530 585 - 655 50 - 200 10 - (30) $1,830 - 2,255 $950 - 1,100 440 - 580 590 - 665 50 - 200 (15) - 35 $2,015 - 2,580 485 - 530 (65) - (85) 1 Includes MTM adjustments for 2006-2008 of $280 million (pretax), $210 million (pretax), and $200 million (pretax), respectively Note: If guidance has changed, previous guidance from 11/3/05 is shown in italics directly below 1820

2006 2007 2008 Exploration & Prod. $950 - 1,050 $950 - 1,050 $1,000 - 1,150 Midstream 280 - 300 230 - 270 70 - 90 Gas Pipeline 710 - 785 390 - 490 410 - 510 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,950 - 2,150 $1,600 - 1,800 $1,500 - 1,750 Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 11/3/05 is shown in italics directly below Consolidated 2006-08 Capital Expenditures 1,425 - 1,625 600 - 680 300 - 390 1,825 - 2,050 230 - 250 180 - 220

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 11/3/05 is shown in italics directly below Dollars in millions 2006-08 Outlook Consolidated Segment Profit Reported MTM Adjustment After MTM Adjustment DD&A Cash Flow from Ops. Capital Expenditures Operating Free Cash Flow 1 2006 2007 $1,240 - 1,580 280 1,520 - 1,860 790 - 890 1,625 - 1,925 1,950 - 2,150 (325) - (225) 2008 $1,620 - 2,045 210 1,830 - 2,255 900 - 1,000 1,850 - 2,150 1,600 - 1,800 250 - 350 $1,815 - 2,380 200 2,015 - 2,580 1,000 - 1,100 2,200 - 2,600 1,500 - 1,750 700 - 850 1,600 - 2,025 230 1,425 - 1,625 (200) - (125) 1,250 - 1,550 270 1,825 - 2,050 425 - 525 1,820

Strong Operating Cash Flow Growth & Increasing Investment Opportunities 2003 2004 2005 2006 2007 2008 Cap Ex-Low 790 1415 1950 1600 1500 Cap Ex-High 790 1415 2150 1800 1750 CFFO-Low 588 1472 1450 1625 1850 2200 CFFO-High 588 1472 1450 1925 2150 2600 Debt to Cap 0.75 0.623 0.586 0.55 0.53 0.51 0.75 0.623 0.586 0.57 0.55 0.53 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,472 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 3 Includes Purchases of Long-term Investments 62% 55% to 57% 53% to 55% Consolidated $790 Opportunity Rich $1,625 to $1,925 $1,950 to $2,150 Declining Debt / Cap % $2,200 to $2,600 59% 51% to 53% $1,415 3 $1,450 $1,500 to $1,750 $1,600 to $1,800 Cap Ex $1,850 to $2,150 Increasing Cash Flow

Segment Profit Guidance Trend 2004 2005 2006 2007 2008 SPAM Low 1263 1577 1520 1830 2015 SPAM High 1263 1577 1860 2255 2580 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 $1,578 (recurring) $1,520 to $1,860 $1,830 to $2,255 $1,263 (recurring) 1 Includes pretax MTM adjustments of ($118) in 2004, $137 in 2005, $280 in 2006, $210 in 2007, and $200 in 2008. Note: Growth percentages are to midpoint of range Consolidated Segment Profit After MTM Adjustments 1 $2,015 to $2,580 7.1% 24.9% 20.9% (Year-Over-Year Growth) (Year-Over-Year Growth) (Year-Over-Year Growth) 12.5% (Year-Over-Year Growth)

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 Expect to grow key earnings measure at 15% rate Opportunity rich Investing in value growth 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

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

EBITDA Reconciliation Non-GAAP Reconciliation

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 4Q 2005 Segment Contribution Non-GAAP Reconciliation

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

Net Income $280 - 440 Loss from Disc. Ops. 5 - 0 Net Interest 665 - 705 DD&A 790 - 890 Provision for Income Taxes 200 - 315 Other/Rounding 10 - 0 EBITDA $1,950 - 2,350 MTM Adjustments 280 EBITDA - After MTM Adj. $2,230 - 2,630 Dollars in millions 2006 Forecast EBITDA Reconciliation Feb 28 Guidance Non-GAAP Reconciliation

Power 1 $(235) - (135) 10 - 20 $(225) - (115) Gas Pipeline $475 - 520 280 - 300 $755 - 820 Segment Profit (Loss) DD&A Segment Profit Before DDA Other (Primarily General Corporate Expense & Investing Income) Rounding TOTAL E&P $650 - 725 335 - 375 $985 - 1,100 Midstream $400 - 500 190 - 200 $590 - 700 Total $1,240 - 1,580 790 - 890 $2,030 - 2,470 (90) - (120) 10 - 0 $1,950 - 2,350 Corp/ Other $(50) - (30) (25) - (5) $(75) - (35) 2006 Forecast Segment Contribution Non-GAAP Reconciliation Dollars in millions 1 Segment Profit is prior to MTM adjustments

Net Income $280 - 440 Less: Discontinued Operations 5 - 0 Income from Continuing Ops $285 - 440 Non-Recurring Items (Pretax) 30 Less Taxes @ Approx. 39% 12 Non-Recurring After Tax 18 Recurring Income from Cont. Ops $303 - 458 Recurring EPS $0.50 - $0.75 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 280 (109) 171 $474 - 629 $0.78 - $1.03 2006 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts Feb 28 Guidance

Appendix

Fourth 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 $206 $71 $206 $75 Midstream Gas & Liquids 112 236 112 151 Gas Pipeline 93 157 130 157 Power (69) (44) 22 (44) Other (30) (22) - (10) Segment Profit $312 $398 $470 $329 MTM Adjustments - Power (22) (29) Segment Profit after MTM Adjustments $448 $300 Memo: Power after MTM adjustments $0 $(73) Consolidated Reported Recurring 4Q05 4Q04 4Q05 4Q04

2005 Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $587 $236 $558 $251 Midstream Gas & Liquids 471 550 471 471 Gas Pipeline 586 586 574 595 Power (257) 77 (140) 77 Other (104) (43) (23) (13) Segment Profit $1,283 $1,406 $1,440 $1,381 MTM Adjustments 138 (118) Segment Profit after MTM Adjustments $1,578 $1,263 Memo: Power after MTM adjustments ($2) $(41)1 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 was liquidated in 1Q04. / corrected

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% Scheduled Debt Retirements & Amortization (8) Debt Balance @ 12/31/05 $7,713 7.6% Fixed Rate Debt @ 12/31/05 $7,066 7.7% Variable Rate Debt @ 12/31/05 $647 6.3% 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%

2005 Cash Information Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS

Consolidated Diluted EPS from Cont. Ops. $0.34 $0.07 $0.01 $0.11 $0.53 Recurring EPS 0.33 0.11 ($0.01) $0.28 0.72 Recurring EPS after MTM Adj. 0.22 0.17 0.22 0.26 0.86 Average Shares (MM) 599 579 581 609 606 2005 1Q 2Q 3Q 4Q Total Diluted EPS from Cont. Ops. - ($0.03) $0.03 $0.17 $0.17 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 $574 - $591 Amortization Discount/Premium and other Debt Expense 35 - 43 Credit Facilities: (incl. Commitment Fees plus LC Usage) 42 - 52 Interest on other Liabilities 22 - 32 Interest Expense $673 - $718 Less: Capitalized Interest (8) - (13) Net Interest Expense Guidance $665 - $705 Dollars in millions 2006 Consolidated 2006 Interest Expense Guidance

2005 Effective Tax Rates Consolidated

2006 2007 2008 Fixed Price at the basin: Volume (MMcfe/d) 299 172 73 Price ($/Mcfe) $3.82 $3.90 $3.96 NYMEX Collars: Volume (MMcfe/d) 65 15 - Price ($/Mcfe) $6.62 - $8.42 $6.50 - $8.25 At the Basin Collars: NWPL Rockies1 Volume (MMcfe/d) 50 50 - Price ($/Mcfe) $6.05 - $7.90 $5.65 - $7.45 EPNG San Juan1 Volume (MMcfe/d) 80 - Price ($/Mcfe) $5.85 - $9.33 Mid-Continent1 Volume (MMcfe/d) 20 - Price ($/Mcfe) $6.76 - $11.83 Dollars in millions Exploration & Production 2006-08 Hedge Update 1 Please note basin locations not NYMEX

4Q 2005 Net Realized Price Calculation Exploration & Production

Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2001-2005. Does not include Discovery volumes. 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

Midstream Strong Free Cash Flow Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 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. 0 100 200 300 400 500 600 700 800 Capital 2004 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Capital Seg Profit + DDA 2008

2005 vs 2006 Segment Profit Gas Pipeline 2005 Reported Segment Profit $586 Non-recurring Items (12) 2005 Recurring Segment Profit 574 Pipeline Safety Costs - Acctg Change (31) Gulfstream Interest Exp/Completion Fee 1 (15) Subtotal 528 Pacific Connector (6) - 0 Higher DDA/Operating Expenses (50) -(8) 2006 Segment Profit Range $475 - 520 1 Lower equity earnings from Gulfstream LLC in 2006 due to Gulfstream LLC issuing $850 million of new long term debt in October 2005. Note: May not add due to rounding

2003 2004 2005 2006 2007 2008 Mandatory 106 199 329 584 180 165 Maintenance 43 34 40 65 60 55 Expansion 376 22 25 100 200 240 Seg Profit + DDA 862 857 841.4 788 920 933 Gas Pipeline Dollars in millions Strong Free Cash Flow 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 2006 - 2008. 2008

4Q05 Financial Statement Changes for Derivatives During 4Q05, Williams reported the following changes related to its derivative portfolio: The net change in Derivative Assets and Liabilities for E&P was positive reflecting the 2006 decrease in gas prices against a short derivative position. The net change in Derivative Assets and Liabilities for Power was positive, reflecting the increased economic value of the Power derivatives primarily due to the rise in 2007 forward gas prices against our long derivative position. Additional gains were made on price decreases on our short power position. Power NOTE: Change in OCI shown is economic change before taxes. Therefore, change shown does not tie to balance sheet change which is net of taxes.

West Undiscounted Cash Flows Power Expected undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

Mid-Con Undiscounted Cash Flows Power Expected undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

East Undiscounted Cash Flows Power Expected undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

Corp./ E&P Midstream Power Other Total Dollars in millions As of 12/31/05 1Reflects net amount of margins out less margins in. WMB Collateral Outstanding $1 $0 $47 $0 $48 0 1 13 0 14 1 1 60 0 62 745 242 283 91 1,361 746 243 343 91 1,423 1,147 225 322 91 1,785 $(401) $18 $21 $0 $(362) Margins & Ad. Assurances1 Prepayments Subtotal Letters of Credit Total as of 12/31/05 Total as of 9/30/05 Change

Estimated dollars in millions WMB Collateral Sensitivity Note: The margin numbers above assume only the forward marginable position values are included.

Enterprise Risk Management 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). Estimated dollars in millions (except price assumptions)

The Williams Companies, Inc.