EXHIBIT 99.2

Williams 2004 4th Quarter Earnings Release February 23, 2005

Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward-looking words, such as "anticipate," believe," "could," "continue," "estimate," "expect," "forecast," "may," "plan," "potential," "project," "schedule," "will," and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; Our ability to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas; Our gas sales, transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; Electricity, natural gas liquids and gas prices are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses; We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; Our operating results might fluctuate on a seasonal and quarterly basis; Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; Legal proceedings and governmental investigations related to our business; Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; Because we no longer maintain investment grade credit ratings, our counterparties have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; We could be held liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; The continued availability of natural gas reserves to our natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Forward Looking Statements

Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable and possible" 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 a reduced level of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. 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 website at www.williams.com.

Overview Steve Malcolm, Chairman, President & CEO

What You'll Hear Williams delivers strong 4Q performance Midstream sees record quarter due to continued strong margins and record volumes Exploration & Production production volume growth continues Gas Pipeline enjoys best quarter in last two years Power continues positive cash flows Strong consolidated cash flows continue Overview

What You'll Hear Restructuring complete Debt now at $7.8B Debt to capitalization ratio of 61.6% Cash of $1.3B at February 19 Status of litigation and investigations Significant matters resolved in 2004 California utilities' refund claims against Williams Gulf Liquids' insurance arbitration award Significant matters that remain open Securities/ERISA litigation DOJ investigation related to gas price reporting FERC's investigation related to gas storage information Overview

What You'll Hear E&P growing Production up 25% for the year 248% reserves replacement rate with >99% success rate Total proved reserves 3.2 Tcfe Midstream phenomenal Record earnings and NGL production levels Deepwater projects performing well Strong free cash flow* Gas Pipeline consistent Steady performer with year-over-year growth Major projects completed Maintenance and regulatory spending decreasing after 2005 Power reducing risk Additional mid-term deals Cash flow positive Actuals tracking guidance * Defined as segment profit plus DD&A less capital expenditures Overview

What You'll Hear Providing 2007 base case by business unit Opportunities included in our numbers 12 rigs in Piceance; total production growth at 10-15% per year Increasing utilization of existing deepwater projects Rate cases improve segment profit in 2007 Selling megawatts primarily through mid-term contracts Potential upside on the horizon but not included in base case Increasing Piceance rig count New E&P opportunities Major deepwater project Major long-term power contracts Natural gas price strength continues NGL margins above the 5-year average Spark spreads improving beyond current market Will refine guidance as move closer to 2007 Overview

Midstream Enhance competitive position- consider MLP Capture our share of new deepwater production 2005 2006 2007 2008 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES Complete announced expansion projects Northwest capacity replacement Rate cases Expansions / LNG opportunities Accelerate Piceance drilling Powder River permits and dewatering Cost reductions Support growth Optimize use of free cash flow Spark spreads improve Risk Reduction Solid Financial Footing Growth with Discipline Continue to reduce risk, generate cash, meet commitments Continue production growth The Road Ahead Overview

2004 Financial Results Don Chappel, CFO

4th Quarter Year 2004 2003 2004 2003 Income (Loss) from Continuing Ops.* $95 ($73) $93 ($57) Income (Loss) from Disc. Ops.* (22) 20 71 327 Effect of Accounting Change - - - (761) Net Income/(Loss)* $73 ($54) $164 ($492) Net Income/(Loss) Share* $0.13 ($0.10) $0.31 ($1.01) Rcr. Inc./(Loss) from Cont. Ops /Share** $0.12 $0.11 $0.49 ($0.03) Rcr. Inc./(Loss) from Cont. Ops after MTM Adjustments/Share** $0.09 $0.04 $0.35 ($0.33) Financial Results * Includes certain gains on asset sales and impairments and has been restated primarily for discontinued operations (See Notes 1 & 7 of the Financial Highlights). Reflects reclassification of Gulf Liquids to continuing operations. ** A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations and 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) Consolidated

2004 2003 2004 2003 Income/(Loss) from Cont. Ops. $95 ($73) $93 ($57) Gains on Sale of Assets (10) (16) (10) (337) Impairments/Losses/Write-offs 31 106 70 357 Income (Expense) Related to Prior Periods 4 (9) 15 (117) Debt Retirement Expenses 30 67 282 67 Insurance Arbitration Award (103) - (103) - Other - Net 4 33 18 67 Less: Income Tax Provision (17) 50 104 (34) Recurring Income from Cont. Ops. $68 $58 $261 $14 Preferred Dividend - - - (30) Rec. Inc./(Loss) from Cont. Ops. Avail. to Com. $68 $58 $261 ($16) Recurring Income/(Loss) from Cont. Ops/Share $0.12 $0.11 $0.49 ($0.03) Recurring Income from Cont. Operations Dollars in millions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 4th Quarter Year Consolidated

Recurring Income from Cont. Ops After Mark-to-Market Adjustments Consolidated Dollars in millions, except for per-share amounts 4th Quarter Year 2004 2003 2004 2003 Recurring income/(loss) from cont. ops avail. to common shldrs 68 $ 58 $ 261 $ (16) $ Recurring diluted earnings/(loss) per common share 0.12 $ 0.11 $ 0.49 $ (0.03) $ Mark-to-Market (MTM) adjustments for Power: (85) Reverse forward unrealized MTM gains/losses (23) (304) (262) Total MTM adjustments (29) (60) (118) (253) (23) Tax effect of total MTM adjustments (at 39%) (11) (46) (99) Recurring income/(loss) from continuing operations avail. to common shareholders after MTM adjustments 51 $ 22 $ 190 $ (170) $ Recurring diluted earnings/(loss) per share after MTM adj. 0.09 $ 0.04 $ 0.35 $ (0.33) $ Note: Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. - A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com. After tax MTM adjustments (17) (37) (72) (155) Add realized gains/losses from MTM previously recognized (6) 25 186 8

2004 2003 2004 2003 Segment Profit* $398 $153 $1,406 $1,239 Net Interest Expense (170) (240) (828) (1,248) Debt Retirement Expense (30) (67) (282) (67) Other Income/(Expense) - Net (14) (15) (72) 13 Income/(Loss) from Cont. Ops. Before Tax* 184 (169) 224 (63) Provision/(Benefit) for Income Tax 89 (95) 131 (5) Income/(Loss) from Continuing Ops.* $95 ($73) $93 ($58) Income/(Loss) from Discontinued Ops. (22) 20 71 327 Effect of Accounting Change - - - (761) Net Income/(Loss)* $73 ($54) $164 ($492) Net Income Components * Includes certain gains on asset sales and impairments and has been restated primarily for discontinued operations (See Notes 1 & 7 of the Financial Highlights). Reflects reclassification of Gulf Liquids to continuing operations. Dollars in millions (except per share amounts) 4th Quarter Year Consolidated

Fourth Quarter Segment Profit Reported Recurring 4Q04 4Q03 4Q04 4Q03 Exploration & Production $71 $50 $75 $50 Midstream Gas & Liquids(1) 236 64 151 64 Gas Pipeline 157 148 157 148 Power (44) (101) (44) 12 Other (22) (8) (10) (7) Segment Profit(2) $398 $153 $329 $267 MTM Adjustments (29) (60) Seg. Profit after MTM Adjustments $300 $207 Dollars in millions (1) Reflects reclassification o f Gulf Liquids to continuing operations (2) Reported segment profit Includes certain gains on asset sales and impairments and has been restated primarily for discontinued operations (See Notes 1 & 7 of the Financial Highlights). A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated

2004 Segment Profit Reported Recurring 2004 2003 2004 2003 Exploration & Production(1) $236 $401 $251 $310 Midstream Gas & Liquids(2) 550 197 471 283 Gas Pipeline 586 555 595 582 Power(3) 77 135 77 (21) Other (43) (51) (13) (10) Segment Profit(4) $1,406 $1,239 $1,381 $1,144 MTM Adjustments (118) (253) Seg. Profit after MTM Adjustments $1,263 $891 Dollars in millions (1) E&P reported results include $15 million loss provision in 2004 related to prior periods and a gain on sale of $92 million in 2003. (2) Reflects reclassification of Gulf Liquids to continuing operations (3) Power 2003 reported results include $117 million income for prior period item correction. (4) Reported segment profit Includes certain gains on asset sales and impairments and has been restated primarily for discontinued operations (See Notes 1 & 7 of the Financial Highlights). A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated

Recurring Segment Profit after MTM Adj. 4Q2003 $207 Exploration & Production 25 - Higher production volumes +$20 million - Higher net realized price +$2 million - Favorable international & transport +$4 million Midstream 87 - Higher NGL margins +$58 million - Improved olefins results +$26 million Gas Pipeline 9 - Lower G&A expenses +$7 million - Higher Gulfstream earnings +$3 million Power (25) - Lower realized MTM gains -$31 million - Higher realized margins +$1 million - Improved SG&A and Other +$4 million Other (3) Recurring Segment Profit after MTM Adj. 4Q2004 $300 Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Dollars in millions Consolidated

Major Changes in Year Recurring Segment Profit After Mark-to-Market Adjustments Recurring Segment Profit after MTM Adj. 2003 $891 Exploration & Production (59) - Higher production volumes +$14 million - Lower net realized price -$26 million - Higher operating costs -$22 million - 2003 mark-to-market gain -$24 million Midstream 188 - Higher NGL margins +$60 million - Higher NGL volumes +$45 million - Improved domestic olefins +$41 million - Improved Canadian olefins +$25 million Gas Pipeline 13 - Transco & NWP expansion +$37 million - Higher interruptible transport +$14 million - Higher net expenses -$18 million Power 233 - Higher realized MTM gains +$178 million - Higher realized margins +$8 million - Lower SG&A, Op. costs and other +$48 million Other (3) Recurring Segment Profit after MTM Adj. 2004 $1,263 Consolidated Dollars in millions

4Q04 Year Beginning Unrestricted Cash * $976 $2,318 Cash Flow from Continuing Operations 404 1,473 Cash Flow from Discontinued Operations (3) 16 Asset Sales 40 1,053 Restricted Investments (LC Collateral) - 380 Debt Issuance (Transco) 75 75 Debt Retirements (230) (3,267) Capital Expenditures/Investments (249) (790) Debt Premiums/Issuance Costs (33) (273) Dividends (28) (43) Other-Net (22) (12) Ending Unrestricted Cash * $930 $930 Unrestricted Cash at 2/19/05 $1,332 Restricted Cash at 12/31/04 (not included above) $113 $93 Cash Information Dollars in millions * Includes cash for discontinued operations of $2.5 million at 12/31/03 and $0 million at 12/31/04 Consolidated

Debt Balance Debt Balance @ 12/31/03 * $11,978 7.7% Scheduled Debt Retirements & Amortization (831) Tendered Debt Retirements (2,991) Open Market Purchases (269) Debt Issuance (Transco) 75 Debt Balance @ 12/31/04 $7,962 7.4% Less: Scheduled January Retirements (200) Debt Balance @ 1/31/05 $7,762 Fixed Rate Debt @ 12/31/04 $7,300 7.6% Variable Rate Debt @ 12/31/04 $662 4.5% Avg. Cost * Debt is long-term debt due within 1 year plus long-term debt plus notes payable; includes FELINE PACS Dollars in millions Consolidated

Segment profit $1,406 $1,175 - $1,375 Net Interest Expense (828) (810) - (860) Early Debt Retirement Costs (282) (300) - (250) Other (Primarily General Corp. Costs) (72) (90) - (125) Pretax Income (Loss) $224 ($25) - $140 Provision (Benefit) for Income Tax (131) 0 - (80) Income / (Loss) from Continuing Ops $93 ($25) - $60 Income from Discontinued Ops 71 50 - 100 Net Income $164 $25 - $160 Diluted EPS $0.31 $0.05 - $0.30 Net Income - Recurring * $261 $183 - $238 Diluted EPS - Recurring * $0.49 $0.34 - $0.44 Diluted EPS- Recurring After MTM Adjustments $0.35 $0.26 - $0.36 Dollars in millions, except per-share amounts * Excludes early debt retirement costs, gains and losses on assets sales and impairments 2004 2004 vs. Guidance Consolidated Nov. 4 Guidance

EPS Metrics Consolidated EPS $0.02 ($0.03) $0.19 $0.13 $0.31 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS ($1.59) $0.47 $0.20 ($0.10) ($1.01) Recurring EPS (0.10) (0.03) - 0.11 (0.03) Rec. EPS after MTM Adj. (0.12) (0.25) 0.01 0.04 (0.33) Average Shares (MM) 518 525 525 519 518 2003 1Q 2Q 3Q 4Q Total $0.05 - 0.30 0.34 - 0.44 0.26 - 0.36 11/4/04 Guidance

Business Unit Results

Exploration & Production Ralph Hill, Senior Vice President

4th Quarter Year 2004 2003 2004 2003 Segment Profit Dollars in millions Segment Profit $71 $50 $236 $401 Non recurring: Ownership issue 4 - 15 - Gain on sale of assets - - - (91) Recurring Segment Profit $75 $50 $251 $310 Exploration & Production 4Q03 to 4Q04 increase includes Volume increase of 25% Recurring profit increase of 50% Base business sequential quarter improved Volumes increased by 5% Recurring profit increased 7% $91mm negative hedge impact in 4th quarter, $250mm negative hedge impact full year

Strong 2004 Reserves Performance Exploration & Production Domestic proved reserves up 10.5% to 3.0 Tcfe Total proved reserves 3.2 Tcfe 248% reserves replacement 99% success rate Moved 451 Bcfe to proven Transfers of Probable to Proved (Bcf) 2002 2003 2004 Total Total for retained basins 313 408 451 1,172

2004 Accomplishments 4Q 2004 production up 25% or 121 MMcfed since 4Q'03 Strong reserves performance $0.92 2004 F&D cost, much better than industry average Record capital program successfully executed Additional Piceance downspacing approved Drilling initiated in new Piceance areas of Trail Ridge and Ryan Gulch Received environmental awards from EPA, COGCC, and BLM Exploration & Production Sold Properties

Exploration & Production Domestic Proved Reserves Reconciliation -390 -186 +408 +23 -191 +451 Prod. +37 Prod. Acqu. Sold YE 2002 Adds/ Rev. Acqu. Adds/ Rev. YE 2003 YE 2004

Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 3660 2063 960 236 Proved, Probable & Possible Reserves Piceance Powder River San Juan Mid-Cont. & Other Proved Reserves 1830 304 671 181 Total: 3.0 Tcf Proved* * 99% of proved reserves were audited or prepared by Netherland, Sewell & Assoc., Inc. or Miller and Lents, LTD. Total: ~7 Tcf Proved, Probable & Possible ** ** Please reference E&P oil & gas reserves disclaimer concerning reserves estimates. Excludes new opportunities such as Trail Ridge, Ryan Gulch, Red Point. 2004 Year End Proved Reserves Exploration & Production Domestic Reserves

Domestic Production Growth Q1 '02 Q2 '02 Q3 '02 Q4 '02 Q1 '03 Q2 '03 Q3 '03 Q4 '03 Q1 '04 Q2 '04 Q3 '04 Q4 '04 Retained Properties 426 427 492 473 470 475 459 442 457 511 535 566 Sold Properties 121 134 35 31 34 27 2 5 Exploration & Production

Growth Metrics Exploration & Production Note:Assumes mid-point of guidance range

U.S. Natural Gas Production Exploration & Production Source: www.evaluateenergy.com and company press releases * Completed major acquisitions in 2004 Company 4Q 2003 4Q 2004 % Change BP 2,933 2,651 -10% ExxonMobil 2,038 1,810 -11% ChevronTexaco 2,110 1,618 -23% ConocoPhillips 1,469 1,377 -6% Shell Group (RD) 1,397 1,302 -7% Sub-total 9,947 8,758 -12% Devon Energy Corp. 1,748 1,620 -7% Anadarko Petroleum 1,365 1,306 -4% Kerr-McGee* 632 1,041 65% Burlington Resources Inc. 870 916 5% XTO (Cross Timbers)* 738 916 24% EOG Resources 632 666 5% Apache Corp. 686 637 -7% Marathon 737 585 -21% Newfield Exploration* 501 585 17% Williams 447 566 27% Pioneer Natural Resources* 454 547 21% Occidental 525 499 -5% Unocal 566 470 -17% Questar 270 300 11% Amerada Hess 213 178 -16% Sub-total 10,384 10,830 4% TOTAL 20,331 19,588 -3.7% MMcf/d

Finding & Development Cost Comparison Williams' 2004 F&D cost was $0.92 per mcfe. The 3-yr Avg ('02-'04) was $0.78 Industry rolling average F&D cost through 2003 was $1.42 per mcfe Expect industry average to increase due to higher 2004 drilling cost and acquisition activity Exploration & Production Forest Oil Newfield Exploration Devon Energy Anadarko Westport Tom Brown EOG Burlington Pioneer Apache U.S. Natural Gas Production (mmcf/day) 3.23 2.01 1.63 1.39 1.38 1.35 1.25 1.2 1.13 1.06 * Source: RBC Capital Markets Research Comment, dated March 15, 2004

2005 2006 2007 Segment profit $400 - 475 $450 - 525 $500 - 625 Annual DD&A $220 - 250 $250 - 290 $300 - 350 Segment Profit + DD&A $620 - 725 $700 - 815 $800 - 975 Capital spending $500 - 575 $525 - 625 $525 - 675 Production (MMcfe/d) 600 - 700 700 - 800 775 - 875 Hedged Volume (MMcfe/d) 286 298 172 Hedged Price (NYMEX) $4.44 $4.39 $4.20 Dollars in millions Exploration & Production 2005-2007 Guidance

Key Points Exploration & Production Strong 2004 reserves performance Significant volume growth from existing positions Continuing to expand development drilling activity - Piceance is primary growth driver Decreased hedging increases upside Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Maintaining top quartile cost and efficiency position Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles Exciting new Piceance area opportunities

Midstream Alan Armstrong, Senior Vice President

4th Quarter Year 2004 2003 2004 2003 Segment Profit $236 $64 $550 $197 Non recurring: Depreciable Life Adjustment 1 - 7 4 Impairments 17 16 17 109 Insurance Arbitration Award (94) - (94) - Gain on Asset Sales (9) (16) (9) (27) Recurring Segment Profit $151 $64 $471 $283 Dollars in millions 2004 vs. 2003 increase includes $60 million due to higher NGL margins $45 million increased NGL volumes $41 million improvement in domestic olefins $25 million improvement in Canada olefins 4Q04 vs. 4Q03 increase includes $58 million increase in NGL margins and volumes $26 million due to better performance in olefins Midstream Segment Profit Note:Reflects reclassification of Gulf Liquids to continuing operations

4th Quarter and 2004 Accomplishments Record recurring earnings Record domestic NGL production: 2004 record year 4Q record quarter December record month Record number of well connects in 2004 (> 500) Devil's Tower start-up (twice) Opal TXP-IV Expansion Asset sales Gulf Liquids insurance arbitration award finalized and LOI signed on Gulf Liquids asset sales * Excludes gains/losses/impairments 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2003 143.6 89.4 108.7 104.1 2004 150 128 172 197 Recurring Segment Profit + Depreciation* Midstream

Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Margin 5.21 7.7 11.75 12.75 17.16 7.99 6.18 11.01 10.08 8.84 17.64 22.6 Volume (MM Gallons) 292 296 333 271 300 199 228 298 327 328 373 400.5 Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Midstream Margins Above Average Domestic NGL Actual Average Net Margin and Volume by Quarter Margin (Cents / Gallon) Equity Volume by Quarter (MM Gallons)

Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 755.6 799 823 Commodity 301 201 207.7 210 Note: Total revenues less cost of goods sold. Reflects 5 year average (Jan '00 - Dec '04) margins in 2006- 2007 at mid-point of range. Midstream 30% 70% 21% 21% 20% 79% 79% 80%

Deepwater Success-What to Watch For Midstream Gunnison Devils Tower

2005 2006 2007 Segment Profit $350-430 $400-500 $400-520 Annual DD&A $180-190 $185-195 $190-200 Segment Profit + DDA $530-620 $585-695 $590-720 Capital Spending $120-140 $110-130 $100-130 Note: - Guidance does not include any major deepwater projects - If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below Midstream 2005-2007 Guidance $310 - $410 Dollars in millions

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

Key Points Business generated record segment profit in 2004 Operational high marks set Continued strong free cash flows Deepwater cash flows: Continued strength Upside driven by drill-ship availability One-two punch Premier assets in growth basins Attracting volumes through reliability Midstream

Gas Pipeline Phil Wright, Senior Vice President

4Q04 vs. 4Q03 increase includes $7 million due to lower G&A expenses $3 million due to increased Gulfstream earnings 2004 vs. 2003 increase includes $37 million due to full year of Transco and Northwest expansion projects $14 million due to higher interruptible transportation revenue ($18) million due to higher net expenses Segment Profit 4th Quarter Year 2004 2003 2004 2003 Segment profit $157 $148 $586 $555 Includes: Write-off software project - - - 26 Severance accrual - - - 1 Write-off of previously capitalized cost for idled segment - - 9 - Recurring Segment Profit $157 $148 $595 $582 Dollars in millions Gas Pipeline

Fourth Quarter Accomplishments Everett Delta in-service Nov. 10, 2004 26-inch Replacement project filed with FERC Northwest receives Environmental Excellence Award associated with the Evergreen Project Transco set peak day delivery record in December 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2003 209.1 202.5 203.2 213.8 2004 207.8 203 211.7 223.9 Gas Pipeline

Major Project Update Northwest Pipeline Replacement Filed Certificate Application on November 29, 2004 Capital ^ $333 million In-service date, November 2006 Central New Jersey FERC Certificate issued February 10, 2005 Capital ^ $13 million In-service date, November 2005 Leidy to Long Island Pre-filing process underway Capital ^ $100 million In-service date, November 2007 Gas Pipeline

Gulfstream Update Phase II placed in-service February 1st 2005 Project specifics 109-mile, 30" extension to serve Florida Power & Light's Martin plant 350 Mdth/d, long-term commitment by FPL Cost ^ $225 million Capacity under long-term contract Today: 305 Mdth/d (28% of capacity) Mid-2005: 705 Mdth/d (64% of capacity) Gas Pipeline

Future Rate Cases Northwest Next anticipated rate case effective 1Q07 26" capacity replacement primary driver Last rate case effective March 1997 No requirement to file Transco Next rate case effective 1Q07 Last rate case effective September 2001 Required to file Gas Pipeline

Accommodating Imported LNG Expansions on existing LNG Facilities WGP advantages Serves markets that are large, diverse, and growing Proximity to anticipated Gulf Coast LNG Delivery flexibility Low rates Challenges Maintaining gas quality Maintaining flexibility Gas Pipeline

Proposed and Existing LNG Importation Facilities Gas Pipeline

2005 2006 2007 Segment profit $545 - 5851 $515 - 5651,2 $575 - 6351,2 Annual DD&A 280 - 290 290 - 300 300 - 310 Segment profit + DDA 725 - 875 805 - 865 875 - 945 Capital spending 370 - 420 475 - 550 250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below Gas Pipeline $525 - 575 $525 - 575 1) Duke has given notice to terminate their contract related to the Gray's Harbor project and pay Williams a lump sum amount related to the net costs of the project and related income taxes. To date, no formal agreement has been signed. If there is an agreement, the above segment profit range will be adjusted accordingly. 2) Refinancing and additional leverage of Gulfstream is reflected in these amounts. Depending on the timing and amount financed this reflects a decrease from previous guidance of between $10-20 million.

2005-2007 Capital Spending Detail $250 - 325 $475 - 550 $370 - 420 Total 70 - 90 10 - 20 20 - 30 2 276 48 $95 - 130 $95 - 130 $145 - 165 Normal Maintenance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion Note: Major regulatory compliance includes Pipeline Safety and Clean Air Act expenditures as detailed in the 2003 Form 10-K Amounts include AFUDC Sum of ranges may not add due to rounding 85 - 105 95 - 115 160 - 170 Major Regulatory Compliance Gas Pipeline

Key Points Record segment profit in 2004 Rate case preparation in full swing Achieving substantial progress in compliance and reliability investments Transco expansions continue Focused on maintaining low-cost provider status Strong free cash flow generator Stable, low-risk earnings Gas Pipeline

Power Bill Hobbs, Senior Vice President

Gross Margin ($16) $40 $185 $238 SG&A & Other (24) (17) (79) (129) Op. Exp. & Other Inc / (Exp) (4) (124) (29) 26 Segment Profit ($44) ($101) $77 $135 Includes: Asset Impairments - 89 - 103 CA Refund & Other Accrual Adj. - 33 - 33 Prior period correction* - (9) - (117) Regulatory Settlement - - - 20 Gains on sale of assets/contracts - - - (208) Reduction in force costs - - - 13 Recurring Segment Profit ($44) $12 $77 ($21) 4th Quarter Year 2004 2003 2004 2003 Segment Profit Dollars in millions * 2003 amounts reflect corrections as disclosed in 2003 10-K Power

2004 & Recent Accomplishments Success in signing risk-reducing contracts Contracted re-sale of tolls of 550 MW with 1-3 year terms Sale of capacity of 650 MW in 2005 Realized significant free cash flow Reduced risk of portfolio Adopted hedge accounting, reducing earnings volatility Retained top talent Maximized E&P netbacks by maximizing storage and transport contracts Power

Dollars in millions Power Segment Profit after MTM Adjustment 1Schedule of expected realization of MTM gains/losses previously recognized from designated Hedges is included in the Appendix. Combined Power Portfolio Estimated as of 12/31/04 4Q04 A 4Q04 F 2004 A 2005 F 2006 F 2007 F Net Revenues 68 41 582 281 364 435 Tolling Demand Payment Obligations (84) (84) (397) (395) (399) (404) Gross Margin (16) (43) 185 (115) (35) 31 SG&A & Other Inc / (Exp) (28) (31) (108) (68) (65) (66) Segment Profit (44) (74) 77 (183) (100) (35) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) / Losses (23) (304) Add Realized Gains / (Losses) from MTM Previously Recognized (6) 186 Add Expected Realization of Prior Period MTM Gains / Losses Designated Hedges 83 274 99 (23) All Other Derivatives (63) 9 154 189 MTM Adjustments (29) 20 (118) 283 253 166 Segment Profit after MTM Adjustment (73) (54) (41) 100 153 131

Segment Profit to Cash Flow Dollars in millions Power *Includes liquidation of Interest Rate and Crude & Refined Products portfolios. 4th Quarter 2004

Cash Flow Variance Analysis Undiscounted dollars in millions Note: Q4 2004 forecast estimated as of 9/30/04. Q4 2004 Actual cash flows agree in total with Power's Cash Flow Statement; however the allocation of actual cash flows to the various deal types is based on estimates. Power

2005-2007 Guidance Power Note: If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below 2005 2006 2007 Segment Profit/(Loss) ($250) - (150) ($200) - (50) ($100) - 50 MTM Adjustments 300 250 150 Segment Profit after MTM Adj. 50 - 150 50 - 200 50 - 200 Cash Flow from Operations 50 - 150 50 - 200 50 - 200 Capital Expenditures - - - Dollars in millions ($200) - (100) 254 269 100 154

Key Points CFFO expected to remain positive Refocused efforts to offer risk management to customers -- deals getting done Continuing to see improvements in Market liquidity Spark spreads Williams credit Focus remains on reducing risk through longer-term sales Factors impacting guidance Spark spread movement up or down Capacity market timing and value New long-term contracts Power

2005-2007 Consolidated Outlook Don Chappel, CFO

Exploration & Production 400 - 475 Midstream 350 - 430 Gas Pipeline 545 - 585 Other/Rounding 5 - 10 $1,300 - 1,500 Power (250) - (150) Seg. Profit before MTM Adj. $1,050 - 1,350 MTM Adjustments 300 Seg. Profit after MTM Adjust. $1,350 - 1,650 Dollars in millions 2005 2005 Segment Profit Guidance Consolidated Note: If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below. 525 - 575 15 - (10) 1,250 - 1,450 (200) - (100) 1,300 - 1,600 310 - 410 254

Interest on Long-Term Debt $555 - 575 Amortization Discount/Premium and other Debt Expense 25 Credit Facilities: (incl. Commitment Fees plus LC Usage) 30 - 40 Interest on other Liabilities 20 - 30 Interest Expense $630 - 670 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $625 - 660 2005 Interest Expense Guidance Dollars in millions 2005 Consolidated

Segment profit before MTM adjustment $1,050 - $1,350 Net Interest Expense (625) - (660) Other (Primarily General Corp. Costs) (90) - (125) Pretax Income 335 - 565 Provision for Income Tax (155) - (245) Income from Continuing Ops 180 - 320 Income/(Loss) from Discontinued Ops (5) - 5 Net Income $175 - 325 Diluted EPS $0.31 - $0.57 Recurring Income from Cont. Ops $180 - $320 Diluted EPS - Recurring $0.31 - $0.56 Diluted EPS- Recurring After MTM Adjustments (1) $0.63 - $0.88 (1) Includes MTM adjustment of $300 million (pretax) Dollars in millions, except per-share amounts 2005 Consolidated 2005 Forecast Guidance

Dollars in millions 2005-2007 Segment Profit Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. 2005 2006 2007 Consolidated $400 - 475 350 - 430 545 - 585 (250) - (150) 5 - 10 $1,050 - 1,350 300 $1,350 - 1,650 $450 - 525 400 - 500 515 - 565 (200) - (50) 35 - (40) $1,200 - 1,500 250 $1,450 - 1,750 $500 - 625 400 - 520 575 - 635 (100) - 50 0 - (30) $1,375 - 1,800 150 $1,525 - 1,950 310 - 410 525 - 575 $525 - 575 (200) - (100) 15 - (10) 25 - (50) $1,300 Note: If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below $1,300 - 1,600

Segment Profit Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Free Cash Flow (1) Effective Tax Rate (2) Cash Tax Rate 2007 2005 (1) Free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments (2) An additional $25 million income tax expense is forecast in 2005 - 2007 Note: If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below 2006 Dollars in millions $1,050 - 1,350 300 1,350 - 1,650 700 - 775 1,300 - 1,600 1,000 - 1,200 300 - 400 39% 3 - 5% $1,375 - 1,800 150 1,525 - 1,950 800 - 900 1,600 - 1,900 900 - 1,100 700 - 800 39% 5 - 10% $1,200 - 1,500 250 1,450 - 1,750 750 - 850 1,450 - 1,750 1,150 - 1,350 300 - 400 39% 4 - 8% 2005 - 2007 Outlook Consolidated 1,300 - 1,600 900 - 1,200 1,300

Drivers Consolidated Dollars in millions

2005 2006 2007 Exploration & Prod. $500 - 575 $525 - 625 $525 - 675 Midstream 120 - 140 110 - 130 100 - 130 Gas Pipeline 370 - 420 475 - 550 250 - 325 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,000 - 1,200 $1,150 - 1,350 $900 - 1,100 Dollars in millions Notes: - Sum of ranges for each business line does not necessarily match total range - If guidance has changed, previous guidance from 11/4/04 is shown in italics directly below Consolidated 2005 - 2007 Capital Expenditures 1,200

Dollars in millions 2005-2007 Maintenance vs. Growth Capital Note: - Sum of ranges for each business line does not necessarily match total range Explor. & Prod. Growth Maintenance Total Midstream Growth Maintenance Total Gas Pipeline Growth Maintenance Total Power Other/Corp - Maint. Total: Growth Maintenance Total 310 - 365 190 - 210 500 - 575 60 - 75 60 - 65 120 - 140 20 - 30 350 - 390 370 - 420 - 10 - 30 390 - 470 610 - 695 1,000 - 1,200 315 - 395 210 - 230 525 - 625 60 - 75 50 - 55 110 - 130 10 - 20 465 - 530 475 - 550 - 10 - 30 385 - 490 735 - 845 1,150 - 1,350 295 - 425 230 - 250 525 - 675 50 - 70 50 - 60 100 - 130 70 - 90 180 - 235 250 - 325 - 10 - 30 415 - 585 470 - 575 900 - 1,100 2005 2006 2007 Consolidated 1,200

2004 - 2005 Return on Capital Employed Consolidated Dollars in millions

Steady Improvement . . . 2003 2004 2005 2006 2007 CFFO-Low 588 1482 1300 1450 1600 CFFO-High 588 1473 1600 1750 1900 Debt to Cap 0.745 0.623 0.591 0.57 0.54 0.623 0.601 0.59 0.56 Cash Flow 1 Debt / Cap 2 75% Increasing Cash Flow 588 $1,473 $1,300 to $1,600 $1,450 to $1,750 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% 59% to 60% 57% to 59% Decreasing Debt / Cap % 54% to 56% $1,600 to $1,900 New Guidance Consolidated

Guidance Trends 2004 2005 2006 2007 SP Old-Low 1262 1325 1450 1525 SP Old-High 1262 1625 1750 1950 SP New-Low 1348 1050 1200 1375 SP New-H 1348 1350 1500 1800 Cap Ex-Low 790 1000 1150 900 Cap Ex-High 790 1200 1350 1100 $1,000 to $1,200 $1,150 to $1,350 $900 to $1,100 $ Millions $790 $1,375 to $1,800 Segment Profit Cap Ex $1,350 to $1,650 $1,450 to $1,750 $1,525 to $1,950 $1,263 (recurring) $1,050 to $1,350 $1,200 to $1,500 Proforma Seg. Profit after MTM Adjust. * Includes MTM adjustments of ($118) in 2004, $300 in 2005, $250 in 2006, and $150 in 2007 New Guidance Consolidated $1,381 (recurring)

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

Summary Steve Malcolm

Restructuring complete, seeking growth with discipline Opportunities are identified Some already in our guidance Need to bring others across the goal line Will be executing our game plan Measure our success in the upcoming months through updates on our progress Key Points

Q&A

Non-GAAP Reconciliations

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

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

EBITDA Reconciliation 173 DD&A 88 Provision for Income Taxes 170 Net Interest Expense Dollars in millions $73 Net Income* $526 EBITDA* 22 Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments Non-GAAP Reconciliation 669 131 828 $164 $1,721 (71) 4Q04 2004

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Total Segment Profit (Loss) $398 DD&A 173 Segment Profit before DDA $571 General Corporate Expense (35) Investing Income* 22 Other Income (33) TOTAL $526 Gas Pipeline $157 67 $224 Corp/Other ($18) ($21) 3 $122 $283 E&P Midstream $71 $236 51 47 ($39) Power ($44) 5 4Q 2004 Segment Contribution Non-GAAP Reconciliation

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Corp/Other Total Segment Profit (Loss) ($42) $1,406 DD&A 15 669 Segment Profit before DDA ($27) $2,075 General Corporate Expense (120) Investing Income* 34 Other Income (269) TOTAL $1,721 Gas Pipeline $586 264 $850 E&P Midstream $236 $550 192 178 $428 $728 Power $77 20 $97 2004 Segment Contribution Non-GAAP Reconciliation

Net Income Net Income $175 - 325 $175 - 325 Income from Disc. Operations Income from Disc. Operations 5 - (5) 5 - (5) Net Interest Net Interest 625 - 660 625 - 660 DD&A DD&A 700 - 775 700 - 775 Prov. (Benefit) for Income Taxes Prov. (Benefit) for Income Taxes 155 - 245 155 - 245 Other/Rounding Other/Rounding (10) - 0 (10) - 0 EBITDA - Reported & Recurring EBITDA - Reported & Recurring $1,650 - 2,000 $1,650 - 2,000 MTM Adjustments MTM Adjustments 300 300 EBITDA after MTM Adj. EBITDA after MTM Adj. $1,950 - 2,300 $1,950 - 2,300 Dollars in millions 2005 Forecast EBITDA Reconciliation Consolidated 2005

Power (250)-(150) 10 - 20 (240)-(130) Gas Pipeline 545 - 585 280 - 290 825 - 875 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) TOTAL RECURRING E&P 400 - 475 220 - 250 620 - 725 Midstream 350 - 430 180 - 190 530 - 620 Total 1,050 - 1,350 700 - 775 1,750 - 2,125 (100) - (125) 1,650 - 2,000 Corp/ Other 5 - 10 10 - 25 15 - 35 2005 Forecast Segment Contribution Non-GAAP Reconciliation

Net Income $175 - 325 Less: Discontinued Operations 5 - (5) Income from Continuing Ops $180 - $320 Recurring Income from Cont. Ops $180 - $320 Recurring EPS $0.31 - $0.56 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Income from Cont. Ops after MTM Adj. Income from Cont. Ops after MTM Adj. EPS 300 (117) 183 $363 - $503 $0.63 - $0.88 Dollars in millions, except per-share amounts 2005 Forecast Guidance Reconciliation 2005 Non-GAAP Reconciliation

Appendix

2004 Effective Tax Rates Combined Continuing Ops. Disc. Ops. Fourth Quarter 2004 Federal $64 35% $64 35% $0 0% State 17 9% 16 9% 1 500% Foreign 19 10% (2) (1%) 21 10500% Other 10 5% 10 5% 0 0% Tax Provision $110 46% $88 48% 22 11000% Total Year 2004 Federal $107 35% $79 35% $28 35% State 32 11% 28 12% 4 5% Foreign (17) (6%) 6 3% (23) (29%) Other 18 6% 18 8% 0 0% Tax Provision $140 46% $131 58% 9 11% Dollars in millions Consolidated

4Q 2004 Net Realized Price Calculation Exploration & Production

2005 Price Modeling Unhedged Price (NYMEX) $6.34 $5.96 $5.75 2005 2006 2007 Note: Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes Exploration & Production

Enterprise Risk Management Margins & Ad. Assur. $50 $10 $74 - $134 $527 Prepayments 1 - 2 38 - 40 81 Subtotal $50 $12 $112 $ - $174 $608 Letters of Credit 399 123 238 95 894 378 Total as of 12/30/04 $449 $135 $350 $95 $1,068 $986 Total as of 9/30/04 $448 $191 $369 $114 $1,122 Change $1 ($56) ($19) ($19) ($54) Corp./ 12/31/03 E&P Midstream Power Other Total Total Dollars in millions As of 12/30/04 1December 31, 2003 values include certain reclassifications to conform with current presentation.

Enterprise Risk Management Margin volatility (99% confidence interval) - Incremental liquidity requirement 12/30/04 9/30/04 30 days ($106) ($118) 180 days ($268) ($234) 360 days ($353) ($336) Assumption: The margin numbers above consist of only the forward marginable position values, starting from February 2005. Dollars in millions

Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads, for all Williams business units combined. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associated with Spark Spread increase is consistent across all months. Cash flow ranges are not linear. 3 Assumes a non-correlated change in NGL processing spread (i.e. change in NGL price only). Price Increase 2005 2006 2007 WMB Natural Gas (Per MMBtu) $0.10 ($5)-(2) $2-5 $7-10 1 Power West Spark Spread Power Price (Per MWh) $5.00 $5-10 $5-15 $5-15 2 Midstream Processing Margin NGL Price (Per Gallon) $0.01 $10-15 $10-15 $10-15 3 Estimated dollars in millions

Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Power Estimated Total Cash Flows Undiscounted dollars in millions

West - Estimated Total Cash Flows Power Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues.

Central - Estimated Total Cash Flows Power Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues.

East - Estimated Total Cash Flows Power Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2004 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues.