Exhibit 99.2

Williams 2006 1st Quarter Earnings May 4, 2006

Forward Looking Statements Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" 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

Oil and 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.

Overview Steve Malcolm Chairman, President & CEO

Headlines Key earnings measure jumps 19% on 1Q performance Development and step-outs boost proved, probable and possible reserves 22% Activity yields 16% increase over 1Q05 in natural gas production Continued drilling ramp-up designed to deliver more reserves, production growth Integrated model balances volatile commodity markets Company working to complete $360 million transaction with WPZ Financings contribute to stronger balance sheet Overview

Key Operations Accomplishments Increased 1Q natural gas production nearly 100 MMcfe/d Ramp-up in Piceance development continues Deployed 4 new H&P rigs to develop Piceance Basin production Kicked off 2006 drilling in Piceance Highlands Additional 10-acre spacing OK'd Firmed up plan for new NGL take-away capacity from Wyoming Entered into sales hedge for some NGL production Completing steps to put new rates into effect for Transco, Northwest Filled Gulfstream mainline via 23-year agreement Received strong demand for expansions on our interstate gas pipelines Executed additional risk-reducing deals in Power

Financial Results Don Chappel Chief Financial Officer

Financial Results 1st Quarter 2006 2005 Income from Continuing Operations $131 $202 Income (Loss) from Discontinued Operations 1 (1) Net Income $132 $201 Net Income/Share $0.22 $0.34 Recurring Income from Continuing Operations /Share $0.23 $0.33 Recurring Income from Continuing Operations After MTM Adjustments/Share $0.26 $0.22 Dollars in millions ( except per share amounts) A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated

Recurring Income from Continuing Operations 1st Quarter 2006 2005 Income from Continuing Operations $131 $202 Nonrecurring Items Debt Retirement Expense 27 - Regulatory & Litigation Contingencies/Settlements (7) 4 (Income)/expense related to prior periods (6) (6) Gain on sale of assets (7) (8) Other - Net 1 3 Total Nonrecurring items before taxes 8 (7) Tax effect of adjustments (3) 3 Recurring Inc. from Continuing Ops. Avail. to Com. $136 $198 Recurring Income from Cont. Ops./Share $0.23 $0.33 Dollars in millions ( except per share amounts) A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated

Recurring Income from Cont. Ops. after MTM Adjustment Dollars in millions ( except per share amounts) A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated 1st Quarter 2006 2005 Recurring Income from Continuing Ops. Avail. to Common $136 $198 Recurring Diluted Earnings per Common Share $0.23 $0.33 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains) losses (43) (221) Add realized gains from MTM previously recognized 77 113 Total MTM adjustments 34 (108) Tax Effect of Total MTM Adjustments (13) 42 After-Tax MTM Adjustments 21 (66) Recurring Income from Cont. Ops. Avail. to Common Shareholders after MTM Adjustments $157 $132 Recurring Diluted Earnings Per Share after MTM adjustments $0.26 $0.22

First Quarter Segment Profit Dollars in millions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated Reported Recurring 2006 2005 2006 2005 Exploration & Production (see slide 44) $148 $104 $148 $96 Midstream Gas & Liquids (see slide 51) 151 129 145 129 Gas Pipeline (see slide 57) 135 167 133 154 Power (see slide 62) (23) 114 (23) 125 Other 1 (4) 1 (4) Segment Profit $412 $510 $404 $500 MTM Adjustments - Power 34 (108) Segment Profit after MTM Adjustments $438 $392 Memo: Power after MTM Adjustments $11 $17

2006 Cash Information Consolidated 1 1 Cash flow from continuing operations was reduced by the return of $192 million of margin deposits to counterparties Dollars in millions 1st Qtr Beginning Unrestricted Cash 1,597 $ Cash flow from Continuing Operations 165 Debt Retirements (64) Capital Expenditures (468) Dividends (45) Other-Net (70) Change in Cash and Cash equivalents (482) $ Ending Unrestricted Cash at 03/31/06 1,115 $ Restricted Cash at 03/31/06 (not included above) 118 $

Liquidity at March 31, 2006 Consolidated 1 Customer margin deposits payable was reduced by the return of $192 million of margin deposits to counterparties Dollars in millions Cash and cash equivalents 1,115 $ Other current securities 184 Less: Subsidiary and International cash & cash equivalents 284 $ Customer margin deposits payable1 129 (413) Available unrestricted cash 886 Available revolver capacity 1,349 Total Liquidity 2,235 $

Exploration & Production Ralph Hill President

Total 3P Reserves Grow by 22% 8.8 Tcfe 10.7 Tcfe 3P Growth 22% Proved Growth 13% Exploration & Production - 2.0 4.0 6.0 8.0 10.0 12.0 YE '04 YE '05 Reserves, Tcfe Proved Reserves Probable & Possible Reserves

Powder River Up 17 MMcfed or 16% over a year ago Big George production is driving basin growth Net MMcfe/d Exploration & Production Williams' Powder River Production 50 100 150 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06

Piceance Production Growth Up 81 MMcfed or 29% over a year ago 21 rigs currently operating compared to 13 a year ago 6 additional H&P FlexRigs to be received Net MMcfe/d Exploration & Production Williams' Piceance Production 175 225 275 325 375 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06

Low Cost Industry Leader Industry leader in 3-year average F&D cost of $0.92/Mcfe Top quartile in 2005 production cost per Mcfe Top quartile Reserves Replacement Rate of 277% * Source: EvaluateEnergy.com Graph represents top 15 E&P companies ranked by US Natural Gas Reserves Exploration & Production 3-yr Avg ('03-'05) F&D Cost * $0.00 $0.50 $1.00 $1.50 $2.00 Williams XTO Encana ConocoPhillips Burlington Anadarko BP EOG Pioneer Devon Chesapeake ExxonMobil Dominion Chevron Kerr-McGee $/mcfe

Cash Margin Analysis Exploration & Production 3-Year Average (2006-08) Reflective of core basins $5.55 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) $5.75 Previous Previous $3.98 $1.77 Cash Margin Cash Costs $5.55 $1.73 $0.92 $3.82 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs

Rockies Producer Not Rockies Price Taker Exploration & Production Powder River Piceance San Juan Glenrock Opal Wamsutter Cheyenne Greasewood Blanco Meeker CIG NWPL Questar Rockies Express TransColorado WIC Pipes Used to Move Williams ' Gas Trailblazer Firm Access Under Contract North to Wamsutter 200 East to Mid - continent 209 South to San Juan 285 East to Appalachia (REX) 200 West to Opal 150 2008 - 2009 adds

2006-08 Consolidated Outlook Don Chappel Chief Financial Officer

2006 Forecast Guidance Consolidated Segment profit before MTM adjustment $1,273 - $1,613 $1,240 - $1,580 Net Interest Expense (665) - (705) (665) - (705) Other (Primarily General Corp. Costs) (85) - (120) (90) - (120) Pretax Income 523 - 788 485 - 755 Provision for Income Tax (210) - (320) (200) - (315) Income from Continuing Ops 313 - 468 285 - 440 Income/(Loss) from Discontinued Ops (5) - 0 (5) - 0 Net Income $308 - 468 $280 - 440 Diluted EPS $0.50 - $0.77 $0.46 - $0.72 Recurring Income from Cont. Ops $318 - $473 $303 - $458 Diluted EPS - Recurring $0.52 - $0.78 $0.50 - $0.75 Diluted EPS - Recurring After MTM Adj. 1 $0.78 - $1.03 $0.78 - $1.03 1 Includes MTM adjustment of $255 million (pretax) in May 4 guidance and $280 million (pretax) in Feb 28 guidance Note: Fully diluted shares of 610 million Dollars in millions, except per-share amounts May 4 Guidance Feb 28 Guidance

2006-08 Segment Profit Consolidated Dollars in millions Exploration & Production Midstream Gas Pipeline Power 1 Other / Corp. / Rounding Total Reported Before MTM Adj. MTM Adjustment Total Reported After MTM Adj. Nonrecurring Items Total Recurring After MTM Adj. 2006 2007 $525 - 625 500 - 600 475 - 520 (205) - (105) (22) - (27) $1,273 - 1,613 255 $1,528 - 1,868 (8) $1,520 - 1,860 2008 $775 - 900 410 - 530 585 - 655 (165) - (15) 10 - (30) $1,615 - 2,040 215 $1,830 - 2,255 - $1,830 - 2,255 $950 - 1,100 440 - 580 590 - 665 (165) - (15) (15) - 35 $1,800 - 2,365 215 $2,015 - 2,580 - $2,015 - 2,580 Note: If guidance has changed, previous guidance from 2/28/06 is shown in italics directly below 650 - 725 400 - 500 $1,520 - 1,860 (55) - (35) 280 - $1,240 - 1,580 $1,620 - 2,045 $1,815 - 2,380 (235) - (135) (160) - (10) (150) - 0 210 200 1 Power's segment profit guidance after MTM adjustments is unchanged at 50 -150 in 2006, 50 - 200 in 2007, and 50 - 200 in 2008

2006-08 Capital Expenditures Consolidated Exploration & Prod. Midstream Gas Pipeline Power Other/Corporate Total Dollars in millions Notes: - Sum of ranges for each business line does not necessarily match total range $950 - 1,050 280 - 300 710 - 785 - 10 - 30 $1,950 - 2,150 $950 - 1,050 230 - 270 390 - 490 - 10 - 30 $1,600 - 1,800 $1,000 - 1,150 70 - 90 410 - 510 - 10 - 30 $1,500 - 1,750 2006 2008 2007

2006-08 Outlook 1 Cash flow from continuing operations. Reduction from 2006 resulted from margin deposits returned to counterparties. 2 Operating free cash flow is defined as cash flow from continuing operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 2/28/06 is shown in italics directly below Dollars in millions Segment Profit Reported After MTM Adj. Recurring After MTM Adj. DD&A Cash Flow from Ops.1 Capital Expenditures Operating Free Cash Flow 2 2006 2007 $1,528 - 1,868 1,520 - 1,860 790 - 890 1,500 - 1,800 1,950 - 2,150 (450) - (350) 2008 $ 1,830 - 2,255 1,830 - 2,255 900 - 1,000 1,850 - 2,150 1,600 - 1,800 250 - 350 $2,015 - 2,580 2,015 - 2,580 1,000 - 1,100 2,200 - 2,600 1,500 - 1,750 700 - 850 $1,520 - 1,860 Consolidated 1,625 - 1,925 (325) - (225)

Strong Operating Cash Flow Growth & Increasing Investment Opportunities Consolidated 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% $790 Opportunity Rich 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 $1,500 to $1,800 $1,950 to $2,150 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400 2,600 2004 2005 2006 2007 2008 30% 40% 50% 60% 70% 80% 90% 100%

Financing Activities to Date Increased Equity Early conversion of $220 million of 5.5% Junior Subordinated Convertible Debentures reduced debt and increased equity Removed Secured Debt Retired $486MM Williams Production RMT term loan Replaced $1.275B secured revolver with $1.5B unsecured revolver credit facility Issued $200MM in Senior Unsecured Notes at Transco Retired $64 million of debt at maturity Consolidated

Planned Future Financing Transactions Senior Unsecured WMB offering to refinance a portion of recently retired Williams Production RMT term loan Debt & Equity offering at WPZ to fund Four Corners acquisition Financing at NWP to fund capital projects This information shall not constitute an offer to sell or solicitation of an offer to buy any securities. Consolidated

Financial Strategy/Key Points 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(r) -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(r) drives value creation Consolidated

Summary Steve Malcolm Chairman, President & CEO

Headlines Key earnings measure jumps 19% on 1Q performance Development and step-outs boost proved, probable and possible reserves 22% Activity yields 16% increase over 1Q05 in natural gas production Continued drilling ramp-up designed to deliver more reserves, production growth Integrated model balances volatile commodity markets Company working to complete $360 million transaction with WPZ Financings contribute to stronger balance sheet Overview

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 Reconciliation of Income from Continuing Operations to Recurring Earnings (Loss) (UNAUDITED) (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr Income from continuing operations available to common stockholders $202.2 $40.7 $5.7 $68.8 $317.4 $131.1 Income from continuing operations - diluted earnings (loss) per common share $0.34 $0.07 $0.01 $0.11 $0.53 $0.22 Nonrecurring items: Exploration & Production Gain on sale of E&P properties (7.9) - (21.7) - (29.6) - Loss provision related to an ownership dispute 0.3 - - - 0.3 - Total Exploration & Production nonrecurring items (7.6) - (21.7) - (29.3) - Gas Pipeline Prior period liability corrections - TGPL (13.1) (4.6) - - (17.7) - Prior period pension adjustment - TGPL - (17.1) - - (17.1) - Income from favorable ruling on FERC appeal (1999 Fuel Tracker) - - (14.2) - (14.2) - Prior period inventory corrections - TGPL - - - 27.5 27.5 - Accrual of contingent refund obligation - TGPL - - - 9.8 9.8 - Reversal of litigation contigency due to favorable ruling - TGPL - - - - - (2.0) Total Gas Pipeline nonrecurring items (13.1) (21.7) (14.2) 37.3 (11.7) (2.0) Midstream Gas & Liquids Settlement of an international contract dispute - - - - - (6.3) Total Midstream Gas & Liquids nonrecurring items - - - - - (6.3) Power Accrual for a regulatory settlement (1) 4.6 - - - 4.6 - Accrual for litigation contingencies (1) - 13.1 0.4 68.7 82.2 - Impairment of Aux Sable - - - 23.0 23.0 - Prior period correction 6.8 - - - 6.8 - Total Power nonrecurring items 11.4 13.1 0.4 91.7 116.6 - Other Impairment of Longhorn - 49.1 - 38.1 87.2 - Write-off of capitalized project development costs - 4.0 - - 4.0 - Gain on sale of real property - - - (9.0) (9.0) - Total Other nonrecurring items - 53.1 - 29.1 82.2 - Nonrecurring items included in segment profit (loss) (9.3) 44.5 (35.5) 158.1 157.8 (8.3) Nonrecurring items below segment profit (loss) Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss - Midstream) - (8.6) - - (8.6) - Loss provision related to an ownership dispute - interest component (Interest accrued - Exploration & Production) 2.7 - - - 2.7 - Directors and officers insurance policy adjustment (General corporate expenses - Corporate) - - 13.8 - 13.8 - Loss provision related to ERISA litigation settlement (Other income (expense) - net - Corporate) - - 5.0 - 5.0 - Legal fees associated with shareholder litigation (General corporate expenses - Corporate) - - - 9.4 9.4 1.2 Reversal of interest accrual related to reversal of litigation contingency noted above (Other interest expense - Gas Pipeline - TGPL) - - - - - (5.0) Premium and fees related to convertible debt conversion - (Other income (expense) - net - Corporate) - - - - - 27.0 Gain on sale of Algar/Triangulo shares (Investing income / loss - Other) - - - - - (6.7) 2.7 (8.6) 18.8 9.4 22.3 16.5 Total nonrecurring items (6.6) 35.9 (16.7) 167.5 180.1 8.2 Tax effect for above items (1) (2.8) 10.7 (6.4) 48.0 49.5 3.4 Adjustment for nonrecurring excess deferred tax benefit - - - (20.2) (20.2) - Recurring income (loss) from continuing operations available to common stockholders $198.4 $65.9 ($4.6) $168.1 $427.8 $135.9 Recurring diluted earnings (loss) per common share $0.33 $0.11 ($0.01) $0.28 $0.72 $0.23 Weighted-average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 607,073 2005 2006 Note: The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding. (1) No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million and $42 million of the accrual for litigation contingencies in 2nd quarter 2005 and 4th quarter 2005, respectively. The tax rate applied to Midstream's international contract dispute settlement in 1st quarter 2006 is 34%.

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation Reconciliation of Segment Profit to Recurring Segment Profit (UNAUDITED) (Dollars in millions) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr Segment profit (loss): Exploration & Production 103.7 $ 118.3 $ 158.8 $ 206.4 $ 587.2 $ 147.6 $ Gas Pipeline 167.4 164.5 161.1 92.8 585.8 134.7 Midstream Gas & Liquids 128.6 109.1 121.1 112.4 471.2 151.5 Power 114.1 (75.0) (226.4) (69.4) (256.7) (22.5) Other (4.1) (60.5) (10.1) (30.3) (105.0) 1.0 Total segment profit 509.7 $ 256.4 $ 204.5 $ 311.9 $ 1,282.5 $ 412.3 $ Nonrecurring adjustments: Exploration & Production (7.6) $ - $ (21.7) $ - $ (29.3) $ - $ Gas Pipeline (13.1) (21.7) (14.2) 37.3 (11.7) (2.0) Midstream Gas & Liquids - - - - - (6.3) Power 11.4 13.1 0.4 91.7 116.6 - Other - 53.1 - 29.1 82.2 - Total segment nonrecurring adjustments (9.3) $ 44.5 $ (35.5) $ 158.1 $ 157.8 $ (8.3) $ Recurring segment profit (loss): Exploration & Production 96.1 118.3 137.1 206.4 557.9 147.6 Gas Pipeline 154.3 142.8 146.9 130.1 574.1 132.7 Midstream Gas & Liquids 128.6 109.1 121.1 112.4 471.2 145.2 Power 125.5 (61.9) (226.0) 22.3 (140.1) (22.5) Other (4.1) (7.4) (10.1) (1.2) (22.8) 1.0 Total recurring segment profit 500.4 $ 300.9 $ 169.0 $ 470.0 $ 1,440.3 $ 404.0 $ Note: Segment profit (loss) includes equity earnings (loss) and certain income (loss) from investments reported in Investing income (loss) in the Consolidated Statement of Income. Equity earnings (loss) results from investments accounted for under the equity method. Income (loss) from investments results from the management of certain equity investments. 2005 2006

Non-GAAP Reconciliation Schedule - EPS after MTM adjustment Non-GAAP Reconciliation Dollars in millions except per share amounts 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders 136 $ 136 $ Recurring diluted earnings per common share 0.23 $ 0.23 $ Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (43) (43) Add realized gains/losses from MTM previously recognized 77 77 Total MTM adjustments 34 34 Tax effect of total MTM adjustments 13 13 After tax MTM adjustments 21 21 Recurring income from cont. ops available to common shareholders after MTM adjust. 157 $ 157 $ Recurring diluted earnings per share after MTM adj. 0.26 $ 0.26 $ weighted average shares - diluted (thousands) 607,073 607,073 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders 198 $ 67 $ (5) $ 168 $ 428 $ Recurring diluted earnings per common share 0.33 $ 0.11 $ (0.01) $ 0.28 $ 0.72 $ Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (221) (22) 141 (70) (172) Add realized gains/losses from MTM previously recognized 113 77 72 48 310 Total MTM adjustments (108) 55 213 (22) 138 Tax effect of total MTM adjustments (42) 21 83 (8) 53 After tax MTM adjustments (66) 34 130 (14) 85 Recurring income from cont. ops available to common shareholders after MTM adjust. 132 $ 101 $ 125 $ 154 $ 513 $ Recurring diluted earnings per share after MTM adj. 0.22 $ 0.17 $ 0.22 $ 0.26 $ 0.86 $ weighted average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 2005 2006

EBITDA Reconciliation Non-GAAP Reconciliation Dollars in millions 1Q06 Net Income 132 $ (Gain)/Loss from Discontinued Operations (1) Net Interest Expense 160 DD&A 197 Provision for Income Taxes 88 EBITDA 576 $

1Q 2006 Segment Contribution Non-GAAP Reconciliation Dollars in Millions Corp/ E&P Gas Pipeline Midstream Power Other Total Segment Profit (Loss) 148 $ 135 $ 151 $ (23) $ 1 $ 412 $ DD&A 73 69 49 3 3 197 Segment Profit before DDA 221 $ 204 $ 200 $ (20) $ 4 $ 609 $ General Corporate Expense (32) Investing Income* 25 Other Income (26) TOTAL 576 $ * Excluding equity earnings and income (loss) from investments contained in segment profit

2006 Forecast EBITDA Reconciliation Non-GAAP Reconciliation $2,230 - 2,630 255 $1,975 - 2,375 (3) - (8) 210 - 320 790 - 890 665 - 705 5 - 0 $308 - 468 $2,230 - 2,630 280 $1,950 - 2,350 10 - 0 200 - 315 790 - 890 665 - 705 5 - 0 $280 - 440 EBITDA MTM Adjustments EBITDA - After MTM Adj. Other/Rounding Provision for Income Taxes DD&A Net Interest Loss from Disc. Ops. Net Income Dollars in millions May 4 Guidance Feb 28 Guidance

2006 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 $(205) - (105) 10 - 20 $(195) - (85) 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 $525 - 625 335 - 375 $860 - 1,000 Midstream $500 - 600 190 - 200 $690 - 800 Total $1,273 - 1,613 790 - 890 $2,063 - 2,503 (85) - (120) (3) - (8) $1,975 - 2,375 Corp/ Other $(22) - (27) (25) - (5) $(47) - (32) Dollars in millions 1 Segment Profit is prior to MTM adjustments

2006 Forecast Guidance Contribution Non-GAAP Reconciliation 255 (99) 156 $474 - 629 $0.78 - $1.03 $0.52 - $0.78 $318 - 473 5 3 8 $313 - 468 (5) - 0 $308 - 468 30 Non-Recurring Items (Pretax) 12 Less Taxes @ Approx. 39% 18 Non-Recurring After Tax 280 (109) 171 $474 -629 $0.78 - $1.03 $0.50 - $0.75 $303 - 458 $285 - 440 (5) - 0 $280 - 440 Recurring Income from Cont. Ops Recurring EPS Less: Discontinued Operations (Loss) Income from Continuing Ops 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 Net Income Dollars in millions, except per-share amounts Feb 28 Guidance May 4 Guidance

Appendix

Segment Profit 1Q05 to 1Q06 financial highlights include: 16% volume production growth 54% recurring segment profit growth $85 million negative hedge impact in 1Q06 compared to $36 million in 1Q05 1st Quarter 2006 2005 Segment Profit $148 $104 Nonrecurring Gain on sales of assets - (8) Recurring segment profit $148 $96 Dollars in millions Exploration & Production

2006 Accomplishments 1Q06 total production up 16%, 100 MMcfed, since 1Q05 4 H&P rigs drilling Additional Piceance 10-acre spacing approved in April for 11,200 acres Piceance Highlands 2006 drilling program begins Ft. Worth facilities connected and flowing Exploration & Production Recurring Segment Profit + Depreciation 0 50 100 150 200 250 300 1Q 2Q 3Q 4Q 2005 2006

2006-08 Guidance 2006 2007 2008 Segment Profit $525 - 625 $775 - 900 $950 - 1,100 Annual DD&A 335 - 375 425 - 475 475 - 525 Segment Profit + DD&A $860 - 1,000 $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) Average San Juan/Rockies Price $6.09 $6.09 $6.10 Average Mid-continent Price $6.75 $6.75 $6.77 NYMEX $7.50 $7.00 $7.00 Dollars in millions Note: 2006-08 hedge information included in Appendix. Note: If guidance has changed, previous guidance from 2/28/06 is shown in italics directly below. Exploration & Production 650 - 725 985 - 1,100 $8.50 $7.32 2Q-4Q

Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING 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 Exploration & Production

US Natural Gas Reserves Rankings Source: EvaluateEnergy.com Exploration & Production 2005 Reserves Company 2004 2005 Repl. Rate 1 BP 14,081 15,382 72% 2 ExxonMobil 12,329 13,692 112% 3 ConocoPhillips 7,578 7,586 230% 4 Chesapeake 4,374 6,901 659% 5 Anadarko 6,093 6,578 151% 6 XTO 4,715 6,086 463% 7 Burlington 5,076 5,275 146% 8 EnCana 4,636 5,267 400% 9 Devon 4,936 5,164 115% 10 Dominion 4,814 4,856 197% 11 Chevron 3,704 4,428 175% 12 Kerr-McGee 3,772 3,633 -107% 13 Williams 2,986 3,382 277% 14 EOG 2,383 2,948 204% 15 Pioneer 3,000 2,751 48% 16 Shell 2,823 2,680 78% 17 Apache 2,406 2,566 209% 18 Occidental 2,101 2,338 184% 19 El Paso 1,724 1,831 186% 20 Noble 520 1,641 644% Bcf

Williams is a Leader in US Gas Production Growth through the Drill Bit Source: EvaluateEnergy.com Exploration & Production Top 20 U.S. Gas Producers Top 20 U.S. Gas Producers (sorted by 2005 MMcfd) (sorted by Percent Change) Percent Percent Company 2004 2005 change Company 2004 2005 change 1 BP 2,749 2,546 -7.4% 1 Chesapeake 880 1,157 31.5% 2 ExxonMobil 1,947 1,739 -10.7% 2 EnCana 869 1,096 26.1% 3 Chevron 1,873 1,634 -12.8% 3 XTO 835 1,033 23.8% 4 Devon 1,645 1,521 -7.6% 4 Williams 519 612 18.0% 5 ConocoPhillips 1,388 1,381 -0.5% 5 Kerr-McGee 836 962 15.1% 6 Chesapeake 880 1,157 31.5% 6 EOG 631 718 13.8% 7 Shell 1,332 1,150 -13.7% 7 Occidental 507 553 9.1% 8 Anadarko 1,363 1,134 -16.8% 8 Burlington 908 950 4.6% 9 EnCana 869 1,096 26.1% 9 ConocoPhillips 1,388 1,381 -0.5% 10 XTO 835 1,033 23.8% 10 Newfield 540 523 -3.1% 11 Kerr-McGee 836 962 15.1% 11 BP 2,749 2,546 -7.4% 12 Burlington 908 950 4.6% 12 Devon 1,645 1,521 -7.6% 13 Dominion 852 753 -11.6% 13 Apache 647 597 -7.6% 14 EOG 631 718 13.8% 14 Marathon 631 578 -8.4% 15 Williams 519 612 18.0% 15 ExxonMobil 1,947 1,739 -10.7% 16 Apache 647 597 -7.6% 16 Dominion 852 753 -11.6% 17 Marathon 631 578 -8.4% 17 Chevron 1,873 1,634 -12.8% 18 El Paso 650 566 -12.9% 18 El Paso 650 566 -12.9% 19 Occidental 507 553 9.1% 19 Shell 1,332 1,150 -13.7% 20 Newfield 540 523 -3.1% 20 Anadarko 1,363 1,134 -16.8% TOTAL 21,602 21,205 -1.8% TOTAL 21,602 21,205 -1.8% MMcfd MMcfd

2006 2007 2008 Fixed Price at the basin: Volume (MMcf/d) 301 172 73 Average Price ($/Mcf) $3.82 $3.90 $3.96 NYMEX Collars: Volume (MMcf/d) 65 15 - Average Price ($/Mcf) $6.62 - $8.42 $6.50 - $8.25 At the Basin Collars:1 NWPL Rockies Volume (MMcf/d) 50 50 75 Price ($/Mcf) $6.05 - $7.90 $5.65 - $7.45 $6.02 - $9.52 EPNG San Juan Volume (MMcf/d) - 130 25 Average Price ($/Mcf) $5.98 - $9.63 $6.20 - 9.57 Mid-Continent Volume (MMcf/d) - 70 - Price ($/Mcf) $6.78 - $10.89 2006-08 Hedge Update Exploration & Production Dollars in millions 1 Please note basin locations are not NYMEX 2Q-4Q

Segment Profit 1Q06 to 1Q05 financial highlights include: Near record quarter (4Q04 recurring was $151) Higher deepwater production handling revenues Higher revenues from increased G&P fees Slightly exceeded strong 1Q05 net NGL margins Lower olefins margins Higher G&P operating expenses 1st Quarter 2006 2005 Segment Profit $151 $129 Nonrecurring International Contract Settlement (6) Recurring segment profit $145 $129 Dollars in millions Midstream

2006 Accomplishments Midstream Recurring Segment Profit + Depreciation Increased NGL production Cameron Meadows back-on line Entering into forward sale of NGL's Discovery Emergency Open Season volumes New Deepwater development Progress on Overland Pass project Entered into agreement with WPZ for 25.1% interest in Four Corners 0 20 40 60 80 100 120 140 160 180 200 1Q 2Q 3Q 4Q $ MM 2005 2006

2006-08 Guidance 2006 2007 2008 Segment Profit $500 - 600 $410 - 530 $440 - 580 400 - 500 Annual DD&A 190 - 200 200 - 210 210 - 220 Segment Profit + DD&A $690 - 800 $610 - 740 $650 - 800 590 - 700 Capital Spending $280 - 300 $230 - 270 $70 - 90 Dollars in millions Note: If guidance has changed, previous guidance from 02/28/2006 is shown in italics directly below. Midstream Major Growth Projects included in Guidance ($ 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 -

Margins Above Average Midstream 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. Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) 0 5 10 15 20 25 Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Q1'05 Q2'05 Q3'05 Q4'05 Q1'06 0 100 200 300 400 500 600 700 800

Strong Free Cash Flow Midstream 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

NGL Forward Sales (as of April 28, 2006) Midstream Expected equity volume does not include Discovery or Canada NGL volumes. Expected Margin calculated using executed NGL sales and Natural Gas Prices based upon average May - Oct NYMEX strip of $7.10/MMBtu and average May - Oct NWPL basis of $1.65/MMBtu. Expected Margin @ NYMEX Strip Amount of Forward Sales 0 200 400 600 800 1,000 1,200 1,400 Expected Equity Volume (Annual) Forward Sales Volume (May- Oct) Volume (MM Gals) 0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 Avg 5 Yr Opal Frac Spread Expected Margin Price ($/Gallon)

1st Quarter 2006 2005 Segment Profit $135 $167 Nonrecurring Excess royalty reserve reversal (2) - Income related to prior period - (13) Recurring segment profit $133 $154 Segment Profit 1Q05 to 1Q06 financial highlights include: 2006 $2 million - environmental credit sales $15 million - higher O&M and G&A expenses 2005 recurring income includes: $5 million - Gulfstream completion fee $3 million - operating tax adjustment Dollars in millions Gas Pipeline

2006 Accomplishments Northwest: FERC certificate application filed for Parachute Lateral Successful open season for Jackson Prairie incremental storage service Northwest partners with PG&E and Fort Chicago Energy Partners, LP to develop the Pacific Connector Gas Pipeline Transco: Non-binding open seasons completed for Mobile Bay South and Production Area Mainline expansions Gulfstream: 23-year transportation agreement reached with FPL to provide up to 345 MDth/d Fully subscribes mainline capacity on a long- term basis Open season completed for compression- based expansion adding up to 200 MDth/d Gas Pipeline Recurring Segment Profit + Depreciation 0 50 100 150 200 250 1Q 2Q 3Q 4Q 2005 2006

2006-08 Guidance 2006 2007 2008 Segment Profit $475 - 520 $585 - 655 $590 - 665 Annual DD&A 280 - 300 290 - 310 295 - 315 Segment Profit + DD&A $755 - 820 $875 - 965 $885 - 980 Capital Spending $710 - 785 $390 - 490 $410 - 510 Dollars in millions Note: If guidance has changed, previous guidance from 02/28/06 is shown in italics directly below. Gas Pipeline

2006-08 Capital Spending Detail 2006 2007 2008 Normal Maintenance/Compliance $340 - 405 $210 - 265 $180 - 260 Northwest 26-inch Replacement 276 2 - Expansion 95 - 105 180 - 220 230 - 250 Total $710 - 785 $390 - 490 $410 - 510 Dollars in millions Note: If guidance has changed, previous guidance from 02/28/06 is shown in italics directly below. Gas Pipeline 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 20 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 Note: - Sum of ranges may not necessarily match total range

Strong Free Cash Flow Gas Pipeline Note: - Segment Profit is stated on a recurring basis. - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2006 - 2008. 2005 2006 2007 2008 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion 26-inch Replacement Maint/Compliance Dollars in millions 0 100 200 300 400 500 600 700 800 900 1000

Segment Profit Variance in 1Q05 to 1Q06 Segment Profit after MTM primarily due to: Increased power results offset by NG storage and legacy results Decrease in expenses (including SG&A) of $27 million, includes $24 million gain related to sale of certain Enron receivables Power

2006-08 Guidance Note: If guidance has changed, previous guidance from 2/28/06 is shown in italics directly below. Power 1 2006-2008 Portfolio cash flow guidance assumes no use of Working Capital. Changes in Working Capital are likely if future commodity prices are volatile or if collateral is returned to counterparties, or if counterparties exchange Letters of Credit for cash held by WMB. Payment of regulatory and litigation/settlement accruals are not included in portfolio cash flow guidance. Dollars in millions 2006 2007 2008 Prior Guidance - Segment Loss before MTM Adj ($235) - (135) ($160) - (10) ($150) - (0) Est. Fwd Impact of 1Q06 MTM Earnings New Guidance - Segment Loss before MTM Adj ($205) - (105) ($165) - (15) ($165) - (15) (235) - (135) (160) - (10) (150) - (0) Estimated MTM Adjustments 255 215 215 280 210 200 Segment Profit after MTM Adj 50 - 150 50 - 200 50 - 200 Recurring Segment Profit after MTM Adj $50 - 150 $50 - 200 $50 - 200 Power Standalone Cash Flows 1 $50 - 150 $50 - 200 $50 - 200 Capital Expenditures - - - 30 (5) (15)

1Q 2006 - Segment Profit/(Loss) to Cash Flow from Ops Power 1Significant amount of Working Capital used was returned to two counterparties due to commodity settlements and commodity price changes. 2Collateral returned does not impact total WMB liquidity because collateral received is excluded from calculation of available WMB liquidity. Dollars in Millions Commodity Working Power Capital/ & NG Other CFFO Segment Profit/(Loss) ($26) $3 ($23) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (43) (43) Add Realized Gains from MTM Previously Recognized 77 77 Segment Profit/(Loss) After MTM Adjustments 8 3 11 Total Working Capital Change 1&2 (153) (153) Power Segment CFFO 8 (150) (142) Est. Working Capital Used for Other Business Units 151 151 Power Standalone CFFO $8 $1 $9

Cash Flow Analysis Estimated undiscounted dollars in millions 1 Q106 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. Q106 forecast combines Hedged Cash Flow and Merchant Cash Flow estimates to present comparable to actual. 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 SG&A includes $24 million gain related to sale of certain Enron receivables 5 Working Capital & Other changes are zero in future periods, as they are not reasonably estimable. Note: Q106 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 3/31/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Power Actual vs. Forecast 2006 1Q06A 1Q06F 2006A+F 2007F 2008F Tolling Demand Payment Obligations ($86) ($86) $0 ($397) ($402) ($407) Hedged Cash Flows 2 585 503 524 Merchant Cash Flows 3 43 92 85 SG&A and Other 4 1 (21) 22 (85) (85) (80) Total Cash Flows $46 $29 $17 $146 $108 $122 Working Capital & Other 5 (188) 0 (188) (188) 0 0 Estimated Power Segment Cash Flows ($142) $29 ($171) ($42) $108 $122 YTD Variance 131 1 (5) 136

New contracts since February 28 call Power Tenaska - Lindsay Hill Southeast Utility 56 Mar 06 - Dec 06 Tenaska - Lindsay Hill Utility 106 Mar 07 - Dec 09 Red Oak (closed in April 06) Northeast Utility 100 Summer 07 Ironwood (closed in April 06) Northeast Muni 200 Jun 06 - May 07 Ironwood (closed in April 06) Northeast Muni 200 Jun 06 - May 07 Kinder Morgan (closed in April 06) Mid Con Utility 250 Summer 06 AES 400 (closed in Feb 06 West Retail Aggregator 175 Jun06 - Dec 06

New Deals Since 2004 Add to Estimated Hedged Cash Flows $580 million increase Demand payments plus SG&A Undiscounted dollars in millions Merchant on 3/31/06 Hedged on 3/31/06 Hedged on 12/31/04 Power $250 $300 $350 $400 $450 $500 $550 $600 $650 $700 2006 2007 2008 2009 2010

Capacity Sold by Year Power Capacity Sold by Year 4,887 4,574 4,532 2,826 2,784 2,471 0 2,000 4,000 6,000 8,000 2006F 2007F 2008F Total Capacity Sold Remaining Available Upside

1Q06 Financial Statement Changes for Derivatives Power During 1Q06, 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 negative, reflecting the 2006 decrease in gas prices against a long derivative position NOTE: Change in OCI shown is before taxes. Therefore, change shown does not tie to balance sheet change which is net of taxes. Dollars in millions Der A/L OCI MTM Gain/(Loss) Realized (Gain)/Loss Total Change in Consolidated Derivative Values $269 $189 $51 $29 Less change in Option Premiums/Prudency/Other 3 3 Remaining Change in Consolidated Derivative Values $266 $189 $51 $26 Change in E&P Hedge Values 477 375 8 - Prior MTM Realized (Ineffectiveness) (2) - OCI Realized 96 Change in Power Hedge Values (211) (186) 43 - Prior MTM Realized (77) - OCI Realized 9 Balance Sheet Income Statement

West Undiscounted Cash Flows Power 1 Q106 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: Q106 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 3/31/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions West Power Portfolio Estimated as of 3/31/06 Q1'06A 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($38) ($152) ($153) ($155) Hedged Cash Flows 2 $89 $430 $400 $377 Merchant Cash Flows 3 $0 $1 $1 $4 Total Cash Flows $51 $279 $248 $226 Capacity Available (in MW) 3,783 3,783 3,783 Total Capacity Sold 2,765 3,392 3,348 Remaining Capacity Available 1,018 391 435

Mid-Con Undiscounted Cash Flows Power 1 Q106 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: Q106 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 3/31/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions Mid-Continent Power Portfolio Estimated as of 3/31/06 Q1'06A 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($13) ($88) ($89) ($90) Hedged Cash Flows 2 $4 $29 $31 $29 Merchant Cash Flows 3 $0 $15 $19 $21 Total Cash Flows ($9) ($44) ($39) ($40) Capacity Available (in MW) 1,296 1,296 1,296 Total Capacity Sold 639 600 600 Remaining Capacity Available 657 696 696

East Undiscounted Cash Flows Power 1 Q106 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: Q106 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 3/31/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions East Power Portfolio Estimated as of 3/31/06 Q1'06A 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($35) ($158) ($160) ($162) Hedged Cash Flows 2 $34 $127 $71 $118 Merchant Cash Flows 3 $0 $28 $71 $59 Total Cash Flows ($1) ($3) ($18) $15 Capacity Available (in MW) 2,279 2,279 2,279 Total Capacity Sold 1,483 582 584 Remaining Capacity Available 796 1,697 1,695

WMB Collateral Outstanding Enterprise Risk Management As of 3/31/06 Corp./ Dollars in millions E&P Midstream Power Other Total Margins & Ad. Assur. $152 $0 $27 $0 $179 Prepayments 0 1 9 0 10 Subtotal 152 1 36 0 189 Letters of Credit 497 138 427 64 1126 Total as of 3/31/06 649 139 463 64 1315 Total as of 12/31/05 746 243 343 91 1423 Change ($97) ($104) $120 ($27) ($108)

WMB Collateral Sensitivity Enterprise Risk Management Dollars in millions Margin Volatility (1% chance of exceeding) -Potential incremental collateral requirement Days 3/31/2006 12/30/2005 9/30/2005 6/30/2005 30 ($223) ($325) ($469) ($178) 180 ($769) ($559) ($868) ($458) 360 ($626) ($567) ($926) ($351) Assumption: The Margin numbers above consist of only forward marginable positions.

Sensitivity Analysis Enterprise Risk Management Dollars in millions, except per unit increases Enterprise 1 Power Co. 2 Midstream 3 Natural Gas Power Processing Margin Per MMBtu Per MWh Per Gallon of NGL's Increase $0.10 $1 $0.01 2006 4 $2-$5 $2-$4 $7-$11 2007 $8-$10 $6-$8 $10-$15 2008 $20-$22 $9-$11 $10-$15

Debt Balance1 Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Debt Balance @ 12/31/05 $7,713 7.6% Early Conversions (220) Scheduled Debt Retirements & Amortization (64) Debt Balance @ 3/31/06 $7,429 7.7% Fixed Rate Debt @ 03/31/06 $6,788 7.8% Variable Rate Debt @ 03/31/06 $641 6.7% Consolidated

Diluted EPS from Cont. Ops. $0.22 - - - - Recurring EPS 0.23 - - - - Recurring EPS after MTM Adj. 0.26 - - - - Average Shares (MM) 607 - - - - 2006 1Q 2Q 3Q 4Q Total 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 EPS Metrics Consolidated

2006 Interest Expense Forecast Guidance Consolidated 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

2006 Effective Tax Rates Consolidated Statutory Rate 77 35% State 12 6% Foreign 0 0% Other (1) -1% Tax Provision/(Benefit) 88 40% Effective Tax Rate Guidance 1 Cash Tax Rate Guidance 2 Note 1: Additional income tax expense of $5-15 million in 2006, $10-15 in 2007 and $5-10 million in 2008 is also forecast. Note 2: Discontinued operations in 2006 have an immaterial impact. 2006 8-13% 5-10% 2006 2007 39% 39% 2008 39% 9-14% First Quarter

The Williams Companies, Inc.