The Williams Companies, Inc. 8K Williams Reports Third-Quarter 2006 Financial Results | WMB 2 Nov 06

EXHIBIT 99.2

Williams 2006 3rd Quarter Earnings November 2, 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;

Forward Looking Statements (cont.) 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 Investors are urged to closely consider the disclosures and risk factors in our annual report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2006, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

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 Portfolio delivers strong quarter-over-quarter earnings 38% quarter-over-quarter increase in key earnings measure* 47% jump year-to-date '06 vs. '05 Raising guidance for '06 Production up 22% year over year NGL margins at historic levels Progress on deepwater expansion * Recurring income from continuing operations after mark-to-market adjustments

Well-positioned for near- to long-term value creation E&P - our growth: long-lived natural gas assets and among industry's lowest development costs Midstream - significant growth potential; strong free cash flow from ops and drop-downs; recent record quarters with robust outlook from sustained higher NGL margins Gas Pipeline - anchors credit: expansions support stable and growing cash flows to reinvest in high-return E&P and midstream growth Power: continuing to produce positive cash flow and reduce risk Portfolio: provides inherent commodity hedge EVA-based investments Committed to maintaining or improving credit ratios/ratings Access to low-cost capital via Williams Partners L.P. Premier assets that are opportunity rich Pursuing growth with discipline Solid record of delivering results 2006, 2007, 2008 guidance increased >100% increase in segment profit after mark-to-market effect 2003-2006 Virtually all secured debt eliminated Resolved significant legacy issues >100% return to shareholders in last 8 quarters; increased dividend 20% in 2006 alone Taking action to drive value creation Accelerating MLP dropdowns: $360MM so far in '06 Deep bench of qualifying assets supports annual dropdowns of $1B-$2B thru 2008 E&P production sharply increased, prospects good through 2008 and beyond New projects and rate cases expected to support significantly higher pipeline profits in 2007 and beyond

Portfolio delivers value in various price environments Crude = West Texas Intermediate. Gas = Henry Hub. Source = Energy Information Administration

0 2 4 6 8 10 12 14 16 E&P net realized prices relatively unaffected by cash market drop $/MMBtu Henry Hub $4.32 Opal $4.80 E&P net realized price Net realized price Daily cash market 3Q '05 $5.66 $4.80 $4.18 4Q '05 1Q '06 2Q '06 3Q '06

We move Piceance gas to higher-price markets for sale Insulated from Rockies prices for gas sales Our contracted pipeline capacity to moves our Rockies production to more favorable price markets Firm Capacity Under Contract Wamsutter 200 East to Mid continent 209 South to San Juan 285 East to Appalachia (REX) 200 Opal 150 Addt'l Firm Capacity Coming in '08-'09 150 200 209 200 285

Gas prices based on average Gas Daily settle prices at NWP, Wyoming. NGL prices based on composition weighted average of Mont Belvieu daily liquids prices; does not include fuel or T&F. Oil prices are based on average of daily NYMEX prompt settle prices. Frac Spread Commodity Prices ($/MMBtu) $0 $2 $4 $6 $8 $10 $12 $14 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06 2Q '06 3Q '06 ($/MMBtu) Oil - NYMEX ($/MMBtu) NGL - Mont Belvieu ($/MMBtu) Gas - Opal ($/MMBtu) Commodity prices affect Midstream differently

Current Rockies price softness benefits our Midstream We're a purchaser of Rockies gas to fuel our processing business In strong crude market, lower gas prices dramatically improve the margins for our Midstream business

E&P Business creates net long position... All values are undiscounted International E&P volumes are not included Projected E&P volumes are reduced by 20% for fuel & shrink and production taxes Hedges are presented in terms of price exposure. Because some hedges have option characteristics, this volume may be different from notional hedge volumes Economic Natural Gas Exposure for E&P (4Q 2006-2008) (500,000) (250,000) 0 250,000 500,000 750,000 1,000,000 4Q 2006 2007 2008 E&P Gross Commodity Position E&P Net Commodity Position E&P Net Commodity Position MMBtu/Day

....which is offset by Midstream gas use All values are undiscounted International E&P volumes are not included Projected E&P volumes are reduced by 20% for fuel & shrink and production taxes Hedges are presented in terms of price exposure. Because some hedges have option characteristics, this volume may be different from notional hedge volumes Economic Natural Gas Exposure for E&P (4Q 2006-2008) (500,000) (250,000) 0 250,000 500,000 750,000 1,000,000 4Q 2006 2007 MMBtu/Day 2008 E&P Gross Commodity Position E&P Net Commodity Position Midstream Fuel & Shrink E&P Net Commodity Position

Well-positioned for near- to long-term value creation Premier assets that are opportunity rich Pursuing growth with discipline Solid record of delivering results Taking action to drive value creation

Financial Results Don Chappel Chief Financial Officer

Financial Results 2006 2005 2006 2005 Income from Continuing Operations $ 110 $ 5 $ 177 $ 249 (Loss) from Discontinued Operations (4) (1) (15) (2) Net Income $ 106 $ 4 $ 162 $ 247 Net Income/Share $ 0.18 $ 0.01 $ 0.27 $ 0.42 Recurring Income (Loss) from Cont. Ops./Share $ 0.19 $ (0.01) $ 0.60 $ 0.44 Recurring Income from Continuing Operations After MTM Adjustments/Share $ 0.28 $ 0.22 $ 0.87 $ 0.60 3rd Quarter YTD Dollars in millions ( except per share amounts) Financial Results 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.

Recurring Income from Continuing Operations 2006 2005 2006 2005 Income from Continuing Operations $ 110 $ 5 $ 177 $ 249 Nonrecurring Items Regulatory & Litigation Contingencies Settlements & Related Costs 10 - 253 18 Debt Retirement Expense - - 31 - Impairments/Losses/Write-offs/Contingency Adj. (8) 19 (8) 72 (Income)/expense related to prior periods 11 (14) 4 (42) Gains on sale of assets (8) (22) (15) (38) Other - Net - 1 1 3 Total Nonrecurring Items 5 (16) 266 13 Tax effects of adjustments (2) 6 (81) (2) Recurring Income (Loss) from Cont. Ops. Avail to Com. $ 113 $ (5) $ 362 $ 260 Recurring Income (Loss) from Continuing Ops./Share $ 0.19 $(0.01) $ 0.60 $ 0.44 3rd Quarter YTD Dollars in millions ( except per share amounts) Financial Results 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.

Dollars in millions ( except per share amounts) Recurring Income from Cont. Ops. After MTM Adjustment 2006 2005 2006 2005 Recurring Inc. (Loss) from Cont. Ops. Avail. to Common $ 113 $ (5) $ 362 $ 260 Recurring Diluted Earnings (Loss) per Common Share $ 0.19 $(0.01) $ 0.60 $ 0.44 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains)/losses $ 16 $ 141 $ 11 $ (102) Add realized gains from MTM previously recognized 80 72 257 262 Total MTM Adjustments 96 213 268 160 Tax Effect of Total MTM Adjustments (37) (83) (103) (62) After-Tax MTM Adjustments $ 59 $ 130 $ 165 $ 98 Recurring Inc. from Cont. Ops. Avail. to Common Shareholders after MTM adjustments $ 172 $ 125 $ 527 $ 358 Recurring Diluted Earnings Per Share after MTM adjustments $ 0.28 $ 0.22 $ 0.87 $ 0.60 Note: Adjustments have been made to reverse estimated forward unrealized mark-to-market ("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 mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. Financial Results 3rd Quarter YTD

Third Quarter Segment Profit 2006 2005 2006 2005 Exploration & Production (see slide 54) $145 $159 $145 $137 Midstream Gas & Liquids (see slide 65) 212 121 222 121 Gas Pipeline (see slide 75) 109 161 109 147 Power (see slide 82) (70) (226) (79) (226) Other - (10) - (10) Segment Profit $396 $205 $397 $169 MTM Adjustments - Power 96 213 Segment Profit after MTM Adjustments $493 $382 Memo: Power after MTM Adjustments $17 ($13) Dollars in millions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Financial Results Reported Recurring

2006 2005 2006 2005 Exploration & Production (see slide 54) $412 $381 $412 $352 Midstream Gas & Liquids (see slide 65) 494 359 566 359 Gas Pipeline (see slide 75) 366 493 364 444 Power (see slide 82) (172) (187) (181) (162) Other 1 (75) 1 (23) Segment Profit $1,101 $971 $1,162 $970 MTM Adjustments - Power 268 160 Segment Profit after MTM Adjustments $1,430 $1,130 Memo: Power after MTM Adjustments $87 ($2) 2006 YTD Segment Profit Dollars in millions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Financial Results Reported Recurring

Exploration & Production Ralph Hill President

Piceance Production Growth Up 101 MMcfed or 31% over a year ago 24 total rigs currently operating in Valley and Highlands compared to 15 a year ago 2 additional H&P FlexRigs to be received in 2006 4 Nabors Super Sundowner rigs to be received in early 2007 Williams will be able to high-grade rig fleet Net MMcfe/d Exploration & Production Williams' Total Piceance Production 200 250 300 350 400 450 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06 2Q '06 3Q '06 Highlands Valley

Piceance Highlands - Building Momentum Exploration & Production 39 wells spud year to date 24 MMcfed current net production, up from 5 MMcfed year ago Averaged 8 rigs operating during 3Q06 Major road, pipeline, and facilities under construction Working towards year round drilling

Piceance Basin: Highlands Ownership Position Exploration & Production Barcus Creek Ryan Gulch Trail Ridge West Trail Ridge Allen Point Grand Valley-Parachute- Rulison Complex Highlands ownership positions outlined in red Farm-In Deals Ryan Gulch Earned 16,000 net acres by drilling 6 wells Allen Point Earned 6,200 net acres by drilling 6 wells Barcus Creek Newly added farm-in deal

Barcus Creek Farm-In Deal Industry wells Barcus Creek Earning Wells Ryan Gulch Wells Exploration & Production Direct bolt-on to Ryan Gulch Project Targets Williams Fork Formation Drill 5 wells by October 2007, with first well currently drilling Earn 45% working interest in ~25,000 gross acres (~11,000 acres net to Williams) 87.5% NRI 45% working interest in future gas gathering/processing systems 600+ potential drill locations (40-acre density) Williams to operate

Midstream Alan Armstrong President

Significant Progress Made on Growth Projects In Development/Proposal 2006 2007 2008+ Spending $900MM-1,500MM Under Negotiation 2006 2007 2008+ Spending $300MM-500MM In Guidance 2006 2007 2008+ Spending $800-900MM Midstream 54% Major Growth Projects Included in Guidance ($ Millions) Project Name - In Service Date 2006 2007 2008 Opal TXP IV (1Q 2006) $33 - - Opal TXP V (2Q 2007) $50 $10 - Blind Faith (2Q 2008) $70 $95 $10 Other Wyoming G&P (4Q '07 + Various) - $50 $30 Western Gulf Deepwater Expansion (3Q '09) $10 $185 $180 37% 31% 25% 7% Deepwater Overland Pass Canadian Tar Sands Western 11% 12% 77% Opal Western Deepwater 32% 10% 58% Deepwater Canadian Tar Sands Western

Midstream Deepwater Lower Tertiary Discoveries

2006-08 Consolidated Outlook Don Chappel Chief Financial Officer

2006 Forecast Guidance Consolidated Segment profit before MTM adjustment $1,430 - $1,645 $1,355 - $1,675 Net Interest Expense (660) - (690) (670) - (710) Other (Primarily General Corp. Costs) (115) - (135) (105) - (125) Securities Litigation Settlement & Related Costs (165) (162) Pretax Income 490 - 655 418 - 678 Provision for Income Tax (225) - (300) (185) - (295) Income from Continuing Ops 265 - 355 233 - 383 Income/(Loss) from Discontinued Ops (20) - 0 (5) - 0 Net Income $245 - 355 $228 - 383 Diluted EPS $0.40 - $0.58 $0.37 - $0.63 Recurring Income from Cont. Ops $450 - $540 $414 - $564 Diluted EPS - Recurring $0.74 - $0.89 $0.68 - $0.92 Diluted EPS - Recurring After MTM Adj. 1 $1.05 - $1.20 $0.95 - $1.20 1 Includes MTM adjustment of $315 million (pretax) in Nov 2 guidance and $275 million (pretax) in Aug 3 guidance Note: Fully diluted shares of 610 million Dollars in millions, except per-share amounts Nov 2 Guidance Aug 3 Guidance

Consolidated 2006-08 Segment Profit Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total Reported Before MTM Adj. MTM Adjustment Total Reported After MTM Adj. Nonrecurring Items Total Recurring After MTM Adj. 2006 2007 2008 Note: If guidance has changed, previous guidance from 8/3/06 is shown in italics directly below Power After MTM Adj. $550 - 600 675 - 750 1 475 - 500 (240) - (190) (30) - (15) $1,430 - 1,645 315 $1,745 - 1,960 61 $1,806 - 2,021 $825 - 950 500 - 750 585 - 655 (75) - 25 10 - (30) $1,845 - 2,350 125 $1,970 - 2,475 - - $1,970 - 2,475 $1,025 - 1,175 550 - 800 590 - 665 (150) - 0 (15) - 35 $2,000 - 2,675 200 $2,200 - 2,875 - - $2,200 - 2,875 $75 - 125 $50 - 150 $50 - 200 650 1 Includes nonrecurring litigation accrual of $70 million in Nov 2 guidance and $68 million in Aug 3 guidance 550 - 675 1 520 (200) - (150) (20) $1,355 - 1,675 275 $1,630 - 1,950 60 $1,690 - 2,010 225 205 (175) - (75) (155) - (5) $1,745 - 2,250 $1,995 - 2,670

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 2006 2008 2007 $1,150 - 1,250 250 - 260 745 - 815 - - 10 - 30 $2,175 - 2,375 $1,150 - 1,250 420 - 460 370 - 470 - - 10 - 30 $2,000 - 2,200 $1,150 - 1,300 260 - 300 340 - 440 - - 10 - 30 $1,800 - 2,050 230 - 270 70 - 90 $2,200 - 2,400 $1,775 - 1,975 $1,575 - 1,825 280 - 300

2006-08 Outlook 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 2008 Consolidated 1 Cash flow from continuing operations. 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 8/3/06 is shown in italics directly below $1,745 - 1,960 1,806 - 2,021 840 - 920 1,500 - 1,800 2,175 - 2,375 (675) - (575) $ 1,970 - 2,475 1,970 - 2,475 960 - 1,060 2,000 - 2,300 2,000 - 2,200 0 - 100 $2,200 - 2,875 2,200 - 2,875 1,050 - 1,150 2,425 - 2,825 1,800 - 2,050 625 - 775 $1,630 - 1,950 1,690 - 2,010 820 - 920 930 - 1,030 1,010 - 1,110 2,200 - 2,400 1,775 - 1,975 1,575 - 1,825 (700) - (600) 225 - 325 850 - 1,000

Strong Operating Cash Flow Growth & Increasing Investment Opportunities Consolidated 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 3 Includes Purchases of Long-term Investments Cash Flow 1 / Cap Ex $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% 56% to 58% 54% to 56% $790 Opportunity Rich Declining Debt / Cap % $2,425 to $2,825 59% 51% to 53% $1,415 3 $1,450 $1,800 to $2,050 $2,000 to $2,200 Cap Ex $1,500 to $1,800 $2,175 to $2,375 $2,000 to $2,300 Cash FIow Increasing 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400 2,600 2,800 3,000 2004 2005 2006 2007 2008 30% 40% 50% 60% 70% 80% 90% 100%

Financial Strategy/Key Points Drive/enable sustainable growth in EVA(r) / shareholder value Strategy to accelerate delivery of MLP benefits to WMB Continue to maintain and/or improve credit ratios/ratings 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

Well-positioned for near- to long-term value creation Premier assets that are opportunity rich Pursuing growth with discipline Solid record of delivering results Taking action to drive value creation

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 - EPS after MTM adjustment Non-GAAP Reconciliation

EBITDA Reconciliation Non-GAAP Reconciliation

3Q 2006 Segment Contribution Non-GAAP Reconciliation

YTD 2006 Segment Contribution Non-GAAP Reconciliation

2006 Forecast EBITDA Reconciliation Non-GAAP Reconciliation Net Income $245 - 355 $228 - 383 Loss from Disc. Ops. 20 - 0 5 - 0 Net Interest 660 - 690 670 - 710 DD&A 840 - 920 820 - 920 Provision for Income Taxes 225 - 300 185 - 295 Other/Rounding 10 (8) EBITDA $2,000 - 2,275 $1,900 - 2,300 MTM Adjustments 315 275 EBITDA - After MTM Adj. $2,315 - 2,590 $2,175 - 2,575 Dollars in millions Nov 4 Guidance Aug 3 Guidance

2006 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 Gas Pipeline Segment Profit / (Loss) DD&A Seg Profit/(Loss) Before DD&A Other (Primarily General Corporate Expense & Investing Income) Securities Litigation Settlement and Related Costs Rounding TOTAL E&P Midstream Total Corp/ Other Dollars in millions 1 Segment Profit is prior to MTM adjustments $(240) - (190) 10 - 15 $(230) - (175) $475 - 500 280 - 300 $755 - 800 $550 - 600 360 - 400 $910 - 1,000 $675 - 750 190 - 200 $865 - 950 $1,430 - 1,645 840 - 920 $2,270 - 2,565 (115) - (135) (165) 10 $2,000 - 2,275 $(30) - (15) 0 - 5 $(30) - (10)

2006 Forecast Guidance Contribution Non-GAAP Reconciliation Net Income $245 - 355 $228 - 383 Less: Discontinued Operations (Loss) (20) - 0 (5) - 0 Income from Continuing Ops $265 - 355 $233 - 383 Non-Recurring Items (Pretax) 266 261 Less Taxes 81 80 Non-Recurring After Tax 185 181 Recurring Income from Cont. Ops $450 - 540 $414 - 564 Recurring EPS $0.74 - $0.89 $0.68 - $0.92 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 315 123 192 $642 - 732 $1.05 - $1.20 275 107 168 $582 - 732 $0.95 - $1.20 Dollars in millions, except per-share amounts Aug 3 Guidance Nov 2 Guidance

Appendix

Exploration & Production

Key Points - Value Creation Continues An industry leader in production growth, cost efficiencies and reserves replacement Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles Strategy remains rapid development of our premier drilling inventory Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns New areas significantly contributing Experienced and talented work force Exploration & Production

2006 2005 2006 2005 Segment Profit $145 $159 $412 $381 Nonrecurring Gains on sales of assets - (22) - (29) Recurring segment profit $145 $137 $412 $352 Segment Profit - Exploration & Production 3Q06 to 3Q05 financial highlights: 21.8% volume production growth Sequential volume growth of 5.7% and 20.5% segment profit growth over second quarter $40 million negative hedge impact in 3Q06 Dollars in millions 2006 YTD to 2005 YTD financial highlights: 19.7% volume production growth 17% recurring segment profit growth $173 million negative hedge impact year to date Exploration & Production 3rd Quarter YTD

2006 Accomplishments 3Q06 production up 22%, 149 MMcfed since 3Q05 Surpassed 800MMcfed 8 H&P rigs drilling Additional 4,080 acres Piceance Valley 10-acre spacing approved Big George/Powder River volumes continue impressive growth Barcus Creek farm-in finalized Barnett Shale Producing ~16MMcfed ~20,000 net acres under lease or farm-out San Juan production at record levels International profits increase Exploration & Production

Powder River Up 28 MMcfed or 24% over a year ago Big George coals driving basin growth Up 80% year over year September vs. June volumes up 12% Anadarko assumes outside operations Net MMcfe/d Exploration & Production Williams' Powder River Production 0 50 100 150 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06 2Q '06 3Q '06 Big George Wyodak/Other

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

Paradox Basin Project Paradox Basin is immediately adjacent to Piceance and Uinta Basins Acreage position increased from 30,608 to 74,000 net acres Formed large Joint Venture with successful Rocky Mountain independent Emerging play targets fractured Gothic Shale Formation First of four planned wells to spud in November Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING Exploration & Production

2006-08 Guidance 2006 2007 2008 Segment Profit $550 - 600 $825 - 950 $1,025 - 1,175 650 Annual DD&A 360 - 400 455 - 505 500 - 550 Segment Profit + DD&A $910 - 1,000 $1,280 - 1,455 $1,525 - 1,725 910-1050 Capital Spending $1,150 - 1,250 $1,150 - 1,250 $1,150 - 1,300 Production (MMcfe/d) 770 - 845 905 - 1,005 990 - 1,140 Dollars in millions Exploration & Production Note: 2006-08 hedge information included in Appendix. Note: If guidance has changed, previous guidance from 8/3/06 is shown in italics directly below. Unhedged Price Assumption ($/Mcf) Average San Juan/Rockies Price $5.87 $6.09 $6.10 Average Mid-continent Price $6.01 $6.75 $6.77 NYMEX $7.13 $7.00 $7.00

Cash Margin Analysis Exploration & Production 3-Year Average (2006-08) Reflective of core basins $5.65 is after hedging and includes average basin market price of $6.21 before hedging Cash costs include LOE, G&A, taxes and gathering F&D costs include acquisition and development expenditures/proved reserves ('03-'05 average) $5.65 Previous Previous $3.90 $1.75 Cash Margin Cash Costs $5.65 $1.81 $0.92 $3.84 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs

3Q Net Realized Price Summary Exploration & Production * Corrected from original edition

2006 2007 2008 Fixed Price at the basin: Volume (MMcf/d) 288 172 73 Average Price ($/Mcf) $3.89 $3.90 $3.96 NYMEX Collars: Volume (MMcf/d) 64 15 - Average Price ($/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 $6.20 - 9.57 Mid-Continent Volume (MMcf/d) - 75 5 Price ($/Mcf) $6.82 - $10.80 $7.23 - $8.62 2006-08 Hedge Update Exploration & Production Dollars in millions 1 Please note basin locations are not NYMEX 4Q

Midstream

Key Points Focused on our strategy of reliability Base business continues to generate healthy returns and free cash flows NGL margins again exceed historic levels - cushioning enterprise impact of lower gas prices Forecast margins in line with current gas/crude pricing relationship Progress continues on deepwater expansions Western growth opportunities abound Midstream

Segment Profit - Midstream 3Q06 to 3Q05 financial highlights: Record NGL unit margins Higher fee revenue Higher Canadian performance Increased operating expenses Financial Results 2006 YTD to 2005 YTD financial highlights: Higher NGL unit margins Higher fee revenue Increased operating expenses 2006 2005 2006 2005 Segment Profit $212 $121 $494 $359 Nonrecurring Accrual for Gulf Liquids litigation 2 - 70 - International Contract Settlement - - (6) - Asset sales, retirement & abandonment (3) - (3) - Accounts payable accrual adjustment 11 - 11 - Recurring segment profit $222 $121 $566 $359 Dollars in millions 3rd Quarter YTD

2006 Accomplishments Midstream Recurring Segment Profit + Depreciation Another record quarter NGL unit margins at new records Canadian Oil Sands YTD '06 vs YTD '05: + 37% in composite unit margins + 86% in production volume Western Gulf Deepwater Expansions Long term processing agreement on Discovery Opal TXP-V construction on track 0 50 100 150 200 250 300 1Q 2Q 3Q 4Q $ MM 2005 2006

2006-08 Guidance 2006 2007 2008 Segment Profit $675 - 750 $500 - 750 $550 - 800 550 - 675 Annual DD&A 190 - 200 200 - 210 210 - 220 Segment Profit + DD&A $865 - 950 $700 - 960 $760 - 1,020 740 - 875 Capital Spending $250 - 260 $420 - 460 $260 - 300 280 - 300 230 - 270 70 - 90 Dollars in millions Note: Guidance is stated on a non-recurring basis. If guidance has changed, previous guidance from 08/03/2006 is shown in italics directly below. Midstream Un-Hedged Price Assumptions 2006 2007 2008 NYMEX Natural Gas ($/Mcf) $7.13 $7.00 $7.00 NYMEX Oil ($/bbl) $67 $55 - $69 $55 - $69 Net Liquid Margin (cents/gallon) 31.0 24.0 26.0

Free Cash Flow - Forecast 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr East 20.4 27.4 90 20.4 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 $'s 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 for base business in excess of five year (4Q01-3Q06) average margin of 14.9 cpg. Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA 2004 2005 2006 2007 2008 Midstream Capital Spending Recurring Segment Profit & DDA $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 Discretionary Expansion Segment Profit Margin Uplift Base Segment Profit + DDA Discretionary Expansion Historic Expansion Maintenance Well Connects

Pricing Assumptions Included in Guidance Midstream Guidance Pricing Assumptions Historic Prices 0 10 20 30 40 50 60 70 80 90 '00 '01 '02 '03 '04 '05 1Q06 2Q06 3Q06 $/bbl 0 2 4 6 8 10 12 14 $/MMBtu Oil WTI ($/bbl) Nat Gas Henry Hub ($/MMBtu) 0 10 20 30 40 50 60 70 80 90 2006 2007 2008 $/bbl 0 2 4 6 8 10 12 14 $/MMBtu High Oil Low Oil Nat Gas Henry Hub ($/MMBtu)

Margins Above Average Midstream Note: Actual realized margins, does not include Discovery volumes. Five year average of 14.9 cpg is calculated for the period 4Q01-3Q06. Domestic NGL Average Realized Net Margin and Volumes by Quarter Realized Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin 0 5 10 15 20 25 30 35 40 45 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 Q2'06 Q3'06 0 100 200 300 400 500 600 700 800 Realized Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons)

Opal Ignacio Echo Springs Gas Processing & Treatment Plants Gathering Areas Kutz Lybrook Markham Cameron Mobile Bay YTD Equity NGL Margins by Region Midstream Domestic Average 31.4 cpg Western Region 32.3 cpg Gulf Coast Region 29.8 cpg Midstream Larose Williams YTD Equity NGL Gallons 64% 36% Western Region Gulf Region

Gas Pipeline

Key Points 26-inch Replacement project construction substantially complete in November Growth projects progressing Rate Cases Progressing Segment Profit remains on target Gas Pipeline

2006 2005 2006 2005 Segment Profit $109 $161 $366 $493 Nonrecurring 1999 Fuel Tracker adjustment - (14) - (14) Excess royalty reserve reversal - - (2) - Pension expense reduction - - - (17) Adjustment to carrying value of certain liabilities - - - (18) Recurring segment profit $109 $147 $364 $444 Segment Profit - Gas Pipeline 3Q06 to 3Q05 financial highlights: Gas Pipeline 2006 YTD to 2005 YTD financial highlights: Decrease is mainly due to: Higher SG&A Costs - $39MM Labor & Benefits Property & Liability Insurance IT Support Costs Higher O&M Costs - $21MM Higher DDA Costs - $10MM Higher Operating Taxes - $7MM Dollars in millions 3rd Quarter YTD Decrease is mainly due to: Higher SG&A costs - $22MM Labor & Benefits Property & Liability Insurance IT Support Costs Higher O&M costs - $4MM Pipeline Safety costs Lower JV Earnings - $8MM Higher DDA - $3MM

2006 Accomplishments Northwest Parachute Lateral Expansion Project receives FERC approval Northwest celebrates 50 years of continuous service Northwest filed rate case June 30th, effective Jan 1st 2007 Transco Leidy to Long Island Expansion project receives FERC approval FERC certificate application filed for Potomac Expansion Project Transco filed rate case August 31st, effective March 1st 2007 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 - 500 $585 - 655 $590 - 665 Annual DD&A 280 - 300 305 - 325 325 - 350 Segment Profit + DD&A $755 - 800 $890 - 980 $915 - 1,015 Capital Spending $745 - 815 $370 - 470 $340 - 440 Dollars in millions Note: If guidance has changed, previous guidance from 08/03/06 is shown in italics directly below. Gas Pipeline 290-310 295-315 475-520 755-820 875-965 885-980

2006-08 Capital Spending Detail 2006 2007 2008 Normal Maintenance/Compliance $375 - 435 $210 - 265 $180 - 260 Northwest 26-inch Replacement 276 2 - Expansion1 95 - 105 160 - 200 160 - 180 Total $745 - 815 $370 - 470 $340 - 440 Dollars in millions Note: If guidance has changed, previous guidance from 08/03/06 is shown in italics directly below. Gas Pipeline Note: - Sum of ranges may not necessarily match total range 1Major Growth Projects (in guidance): 2006 2007 2008 1st full yr Seg. Profit Parachute (In Service 1/07) $50 - 60 $5-10 $9 Leidy to Long Island (In Service11/07) 15 - 20 85 - 100 $1 - 5 20 Potomac (In Service 11/07) 5 - 10 55 - 65 1 - 5 11 Sentinel (In Service Ph1 11/08, Ph2 11/09) 1 - 5 5 - 15 80 - 100 22 Greasewood (In Service 11/08) 0 - 5 20 - 25 5

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 0 200 400 600 800 1000 1200

Rate Case Filing Gas Pipeline Update NWP TGPL Filing Date 6/30/2006 8/31/2006 Base Period 4/05-3/06 6/05-5/06 Test Period 4/06-12/06 6/06-2/07 Effective Date 1/1/07 3/1/07 Rate Base $1.5B $2.95B Cap Structure (Equity) 55% 62% Filed Return on Equity 13.6% 13.8%

Power

2006 2005 2006 2005 Segment Profit/(Loss) ($70) ($226) ($172) ($187) Nonrecurring Accrual for regulatory & litigation Contingencies/Settlements 4 - 4 13 Contingent obligation adjustments (13) - (13) 5 Expense related to prior periods - - - 7 Recurring segment profit/(loss) (79) (226) (181) (162) MTM Adjustment (Recurring) 96 213 268 160 Recurring segment profit/(loss) after MTM Adj. $17 ($13) $87 ($2) Segment Profit - Power 3Q06 to 3Q05 financial highlights Increase in hedged cash flows largely due to benefit of structured hedges 3Q06 includes ($13) million loss due to lower-of-cost-or market write downs on Storage inventory and ($7) million realized losses on Storage injection hedges. These values are forecasted to be recovered when volumes are withdrawn 2006 YTD to 2005 YTD financial highlights Increase in hedged cash flows largely due to benefit of structured hedges Decrease in expenses (including SG&A) includes $25 million gain related to sale of certain Enron receivables and $9 million in other non-recurring items Includes ($20) million loss due to lower-of-cost-or-market write downs on Storage inventory and ($30) million realized losses on Storage injection hedges. These values are forecasted to be recovered when volumes are withdrawn. Includes $51 million gain from liquidation of certain non-core basis positions Dollars in millions Power 3rd Quarter YTD

Dollars in millions 2006 2007 2008 Prior Guidance - Segment Loss before MTM Adj ($200) - (150) ($175) - (75) ($155) - (5) Est. Fwd Impact of 3Q06 MTM Earnings and other portolio adjustments New Guidance - Segment Loss before MTM Adj ($240) - (190) ($75) - 25 ($150) - $0 Estimated MTM Adjustments 315 125 200 275 225 205 Segment Profit after MTM Adj 75 - 125 50 - 150 50 - 200 Recurring Segment Profit after MTM Adj $75 - 125 $50 - 150 $50 - 200 Capital Expenditures - - - - - - (40) 100 5 2006-08 Guidance Note: If guidance has changed, previous guidance from 8/03/06 is shown in italics directly below. Power

YTD 2006 - Segment Profit/(Loss) to Cash Flow from Ops Power 1Significant amount of Working Capital used was returned to one counterparty 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. 3CFFO includes cash margin dollars sent out on behalf of other business units. Dollars in Millions Commodity Working Power Capital/ & NG Other Total Segment Loss ($145) ($27) ($172) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) 11 11 Add Realized Gains from MTM Previously Recognized 257 257 Segment Profit/(Loss) After MTM Adjustments 123 (27) 96 Total Working Capital Change 1,2&3 (198) (198) Power Segment CFFO $123 ($225) ($102)

Power Portfolio Cash Flow Analysis Estimated undiscounted dollars in millions 1 Q306 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. Q306 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 primarily reflect the tolling (spread option) cash flows which have not been hedged. 4 YTD SG&A includes $25 million gain related to sale of certain Enron receivables 5 Working Capital & Other changes are zero in future periods, as they are not reasonable estimable. Current year Actuals include cash flows from the NG portfolio (including storage related losses offset by the monetization of forward positions), however future periods do not include forecasted NG portfolio cash flows. Note: Q306 Forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Power Power Portfolio Actual vs. Forecast 2006 3Q06A 3Q06F YTD06A YTD06F 2006A+F Tolling Demand Payment Obligations ($128) ($127) (1) ($314) ($312) (2) ($400) Hedged Cash Flows 2 187 462 566 Merchant Cash Flows 3 38 59 18 SG&A and Other 4 (10) (21) 11 (29) (63) 34 (67) Total Power Portfolio Cash Flows $28 $77 ($49) $109 $146 (37) $117 Working Capital & Other 5 122 n/a (211) n/a n/a Estimated Power Segment Cash Flows $150 ($102) QTD Variance 166 1 (57) YTD Variance 452 1 (69)

3Q06 Financial Statement Changes for Derivatives Power During 3Q06, 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 3Q06 decrease in gas prices against a short derivative position The net change in Derivative Assets and Liabilities for Midstream was positive reflecting the 3Q06 price decrease on crude and NGL's against a short derivative position The net change in Derivative Assets and Liabilities for Power was negative, reflecting the 3Q06 decrease in gas prices against a long derivative position 1 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 1 $116 $132 ($10) ($6) Change in E&P Hedge Values 291 242 6 - Prior MTM Realized (Ineffectiveness) (7) - OCI Realized 50 Change in Midstream Hedge Values 26 12 - Prior MTM Realized (0) - OCI Realized 14 Change in Power Hedge Values (201) (122) (16) - Prior MTM Realized (80) - OCI Realized 17 Balance Sheet Income Statement

West Undiscounted Cash Flows Power Dollars in millions 1 Q306 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 primarily primarily reflect the tolling (spread option) cash flows which have not been hedged. Note: Q306 Forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. West Power Portfolio Estimated as of 9/30/06 Q306A Q306F QTD Variance 2006F+A Tolling Demand Payment Obligations ($39) ($38) ($1) ($154) Hedged Cash Flows 2 440 Merchant Cash Flows 3 8 Total Cash Flows $80 $100 ($20) $294 Capacity Available (in MW) 3,805 Total Capacity Sold 2,720 Remaining Available (in MW) after all hedges 1,085 (19) 119 1 138

Mid-Con Undiscounted Cash Flows Power 1 Q306 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 primarily reflect the tolling (spread option) cash flows which have not been hedged. Note: Q306 Forecast estimated as of 12/31/05. 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 9/30/06 Q306A Q306F QTD Variance 2006F+A Tolling Demand Payment Obligations ($41) ($41) $0 ($88) Hedged Cash Flows 2 34 Merchant Cash Flows 3 5 Total Cash Flows ($21) ($21) $0 ($49) Capacity Available (in MW) 1,303 Total Capacity Sold 399 Remaining Available (in MW) after all hedges 904 20 1 20 0

East Undiscounted Cash Flows Power 1 Q306 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 primarily reflect the tolling (spread option) cash flows which have not been hedged. Note: Q306 Forecast estimated as of 12/31/05. 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 9/30/06 Q306A Q306F QTD Variance 2006F+A Tolling Demand Payment Obligations ($48) ($48) $0 ($158) Hedged Cash Flows 2 91 Merchant Cash Flows 3 5 Total Cash Flows ($20) $19 ($39) ($62) Capacity Available (in MW) 2,280 Total Capacity Sold 1,559 Remaining Available (in MW) after all hedges 721 28 1 67 (39)

WMB Collateral Outstanding Enterprise Risk Management As of 9/30/06 Corp./ Dollars in millions E&P Midstream Power Other Total Margins & Ad. Assur. $41 $0 $9 $0 $50 Prepayments 0 0 5 0 5 Subtotal 41 0 14 0 55 Letters of Credit 448 131 382 25 986 Total as of 9/30/06 489 131 396 25 1,041 Total as of 12/31/05 746 243 343 91 1,423 Change ($257) ($112) $53 ($66) ($382)

WMB Collateral Sensitivity Enterprise Risk Management Dollars in millions Margin Volatility (1% chance of exceeding) -Potential incremental collateral requirement Days 9/29/2006 6/30/2006 3/31/2006 12/30/2005 30 ($155) ($246) ($223) ($325) 180 ($459) ($580) ($769) ($559) 360 ($471) ($489) ($626) ($567) Assumption: The Margin numbers above consist of only forward marginable positions.

Sensitivity Analysis Dollars in millions, except per unit increases Enterprise Risk Management 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 $0-$2 MM $(1)-$1 MM $2-$4 MM 2007 $5-$8 MM $2-$4 MM $17-$19 MM 2008 $13-$15 MM $5-$8 MM $18-$21 MM

Consolidated

Liquidity at September 30, 2006 Consolidated Dollars in millions Cash and cash equivalents 1,075 $ Other current securities 160 Less: Subsidiary and Int'l cash & cash equivalents 368 $ Customer margin deposits payable 77 (445) Available unrestricted cash 790 Available revolver capacity 1,712 Total Liquidity 2,502 $

2006 Cash Information Consolidated Dollars in millions 3rd Quarter YTD Beginning unrestricted cash 980 $ 1,597 $ Cash flow from continuing operations 634 1,308 Debt retirements (45) (774) Proceeds from debt issuance - - 699 Proceeds from sale of limited partnership units - - 225 Capital expenditures (756) (1,759) Dividends (54) (152) Dividends to minority interests (11) (28) Purchase of auction rate securities (49) (376) Proceeds from sale of auction rate securities 298 320 Other-net 77 15 Change in cash and cash equivalents 94 $ (522) $ Ending unrestricted cash at 9/30/06 1,075 $ Restricted cash at 09/30/06 (not included above) 120 $

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 @ 09/30/06 $7,268 7.7% Variable Rate Debt @ 09/30/06 $150 6.5% Consolidated Additions 699 Early Retirements (485) Scheduled Debt Retirements & Amortization (180) Debt Balance @ 6/30/06 $7,463 7.7% Scheduled Debt Retirements & Amortization (45) Debt Balance @ 9/30/06 $7,418 7.7%

Dollars in millions Debt Amortization - As of 9/30/2006 Consolidated 392 239 54 217 1,168 80 10 8 385 998 2,020 1,851 3 22 $0 $250 $500 $750 $1,000 $1,250 $1,500 $1,750 $2,000 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019-2027 2028-2032 2033

Diluted EPS from Cont. Ops. $0.22 ($.11) $0.19 - $0.29 Recurring EPS 0.23 0.19 0.19 - 0.60 Recurring EPS after MTM Adj. 0.26 0.33 0.28 - 0.87 Average Shares (MM) 607 596 609 - 608 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 $570 - $580 Amortization Discount/Premium and other Debt Expense 25 - 30 Credit Facilities: (incl. Commitment Fees plus LC Usage) 30 - 40 Interest on other Liabilities 45 - 55 Interest Expense $670 - $705 Less: Capitalized Interest (10) - (15) Net Interest Expense Guidance $660 - $690 Dollars in millions 2006

2006 Effective Tax Rates Consolidated 2006 Statutory Rate 77 35% (22) 35% 73 35% 128 35% State 10 5% (1) 1% 14 6% 23 6% Foreign 0 0% 7 - -10% 7 3% 14 4% Nondeductible Expenses (Shareholder Litigation/Convertible Debentures) 0 0% 18 - -28% 0 0% 18 5% Other 1 0% (1) 1% 6 3% 6 2% Tax Provision/(Benefit) 88 40% 1 - -1% 100 47% 189 52% Effective Tax Rate Guidance Cash Tax Rate Guidance Note 1: Additional income tax expense of $35-45 million in 2006, $10-15 in 2007 and $5-10 million in 2008 is also forecast. 10-15% 5-10% 9-14% 2006 2007 2008 39% 39% 39% First Quarter Second Quarter Third Quarter Year-to-Date

The Williams Companies, Inc. (WMB) 8-KWilliams Reports Third-Quarter 2006 Financial Results