EXHIBIT 99.2

Williams 2005 2nd Quarter Earnings Release August 4, 2005

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

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

2Q05 Review Steve Malcolm Chairman, President & CEO

Headlines Key performance measures - moving up E&P segment profit - up more than 100% Domestic gas production - up 18% during half-year NGL sales volumes - up 13% for 6-month period Net cash from operations - up 29% during first quarter Recurring after mark-to-market - up more than 100% Overview

Other Developments Refined 2Q05 earnings guidance Returning more to investors via dividends Hedging gas production price risk with collars Continuing MLP process Williams Partners LP in SEC registration process Filed 3rd amendment to preliminary registration statement No more details in today's call Attending to legacy issues Proposed tax settlement - previously reserved Longhorn impairment - non-cash Litigation - update in 10-Q Overview

Headlines Williams' growth opportunities are growing Exploration & Production Piceance drilling locations and reserves - up significantly Developing new Piceance opportunities Entry into Ft. Worth Basin's Barnett Shale play Expect continued strong production growth Midstream Drilling activity in West boosts demand for services Excellent position to capture new deepwater business Gas Pipeline Seizing opportunities to meet growing demand Returns on growth expected via rate cases Power Growing success in mid-term deals that reduce risk Overview

Financial Results and 2005 Outlook Don Chappel CFO

Financial Results A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts) 2nd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $40 $(18) $243 $(18) Income (Loss) from Disc. Operations 1 - (1) 10 Net Income (Loss) $41 $(18) $242 $(8) Net Income (Loss)/Share $0.07 ($0.03) $0.41 ($0.02) Recurring Inc. from Cont. Ops./Share $0.11 $0.10 $0.45 $0.11 Recurring Inc. from Cont. Ops. After MTM Adjustments/Share $0.17 $0.04 $0.39 $0.17 Consolidated

Recurring Income from Cont. Operations A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Income from Continuing Operations $40 ($18) $243 ($18) Nonrecurring Items Impairments/Losses/Write-offs 53 26 53 26 Expense related to Prior Periods (22) (6) (28) - Gain on Sale of Assets (9) - (17) - Debt Retirement Expense - 97 - 97 Other - Net 14 - 20 Total nonrecurring $36 $117 $29 $123 Tax Effect of Adjustments 10 45 8 47 Recurring Inc. from Cont. Ops. Avail. To Com. $66 $54 $264 $58 Recurring Income from Cont. Ops./Share $0.11 $0.10 $0.45 $0.11 Consolidated

2nd Qtr YTD 2005 2004 2005 2004 Recurring Income from Cont. Operations After Mark-to-Market Adjustments Note: Adjustments have been made to reverse estimated forward unrealized MTM gains and add estimated realized gains from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com. Dollars in millions, except for per-share amounts Recurring Income from Cont. Ops. Avail. To Common $66 $54 $264 $58 Recurring Diluted Earnings per Common Share $0.11 $0.10 $0.45 $0.11 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM gains (22) (69) (243) (93) Add realized gains from MTM previously recognized 77 10 190 146 Total MTM adjustments 55 (59) (53) 53 Tax Effect of Total MTM Adjustments (at 39%) (21) 23 21 (21) After-tax MTM Adjustments 34 (36) (32) 32 Recurring income from Continuing Operations Avail. To Common Shareholders After MTM Adjustments $100 $18 $232 $90 Recurring Diluted Earnings Per Share After MTM adjustments $0.17 $0.04 $0.39 $0.17 Consolidated 2nd Qtr YTD 2005 2004 2005 2004

Net Income Components A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts) Segment Profit $256 $304 $766 $572 Net Interest Expense (163) (222) (327) (461) Debt Retirement expense - (97) - (97) Other Income (Expense) - Net (11) (21) (25) (38) Income from Cont. Ops. Before Tax $82 $(36) $414 $(24) Provision for Income Tax 42 (18) 171 (6) Income (Loss) from Continuing Ops. $40 ($18) $243 ($18) Income (Loss) from Discontinued Ops. 1 - (1) 10 Net Income $41 ($18) $242 ($8) Consolidated 2nd Qtr YTD 2005 2004 2005 2004

Second Quarter Segment Profit A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions Exploration & Production $118 $43 $118 $55 Midstream Gas & Liquids 109 99 109 82 Gas Pipeline 165 133 143 142 Power (75) 44 (62) 44 Other (61) (15) (7) (4) Segment Profit $256 $304 $301 $319 MTM Adjustments - Power 55 (59) Segment Profit after MTM Adjustments $356 $260 Memo: Power after MTM adjustments $(7) $(15) Consolidated Reported Recurring 2Q05 2Q04 2Q05 2Q04

2005 YTD Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $222 $95 $214 $106 Midstream Gas & Liquids 238 209 238 192 Gas Pipeline 332 280 297 289 Power 39 12 64 12 Other (65) (24) (12) (5) Segment Profit $766 $572 $801 $594 MTM Adjustments (53) 53 Segment Profit after MTM Adjustments $748 $647 Memo: Power after MTM adjustments $11 $651 Dollars in millions Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 1 Includes impact of legacy natural gas portfolio that liquidated in 1Q04.

Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 2Q04 $260 Exploration & Production 63 - Higher production volumes +$20million - Higher net realized price +$45 million Midstream 27 - Increased NGL margins +$16 million - Increased Gathering revenues +$9 million - Increase product handling fees +$4 million Gas Pipeline - - Increased Gulfstream earnings +$3 million - Grays Harbor contract termination -4 million Power 8 - Improved Power and Natural Gas Portfolio cash flows +$25 million - Absence of realized gains on interest rate portfolio -$34 million Other (2) Recurring Segment Profit after MTM Adj. 2Q05 $356 Dollars in millions

2Q05 YTD05 Beginning Unrestricted $1,210 $930 Cash flow from Continuing Operations 489 793 Proceeds from Issuing Common1 9 297 Sale of WilTel Note - 55 Contract Termination Payment - 88 Debt Retirements (5) (221) Capital Expenditures (294) (517) Dividends (29) (57) Other-Net (83) (71) Change in Cash and Cash equivalents $87 $367 Ending Unrestricted Cash at 6/30/05 $1,2972 Restricted Cash at 6/30/05 (not included above) $101 Cash Information Dollars in millions Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS 2 Includes international cash ($185), cash to settle legacy matters including tax settlement ($200), AK Quality Bank judgment ($180) and other matters.

Debt Balance Scheduled Debt Retirements & Amortization (6) Debt Balance @ 6/30/051 $7,744 7.5% Fixed Rate Debt @ 6/30/05 $7,089 7.7% Variable Rate Debt @ 6/30/05 $655 5.2% Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Consolidated Debt Balance @ 12/31/041 $7,962 7.4% Scheduled Debt Retirements & Amortization (216) Capitalized Lease 4 Debt Balance @ 3/31/051 $7,750 7.4%

Business Unit Results

Exploration & Production Ralph Hill Senior Vice President

Segment Profit Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Segment Profit $118 $43 $222 $95 Nonrecurring: Ownership Issue - 11 - 11 Gain on sale of assets - - (8) - Recurring Segment Profit $118 $551 $214 $106 2Q04 to 2Q05 financial highlights include: Volume increase of 17.5% Net realized price increase of 35% Recurring profit increase of 115% Base business sequential quarter improved Increased recurring segment profit 23% Increased volumes 6% $55.2 million negative hedge impact in 2Q05, $91.5 million year to date Exploration & Production 1 Does not add due to rounding

Strong Domestic Production Growth Exploration & Production 2004 2005

Volumes rising in all core basins Big George gross production up to 110 MMcf/d San Juan hits record production Increase in Piceance Valley location inventory and probable reserves 11 rigs operating in Piceance Valley, 4 rigs in Trail Ridge & Ryan Gulch H&P first rig on schedule for Nov 1 Ft. Worth-Barnett Shale entry acquisition Exploration & Production 2nd Quarter and 2005 Accomplishments

Piceance Production Growth Up 100 MMcf/d or 48% over a year ago Up 28 MMcf/d or 10% sequentially Exploration & Production

Up 48 MMcf/d or 78% over a year ago Up 25 MMcf/d or 29% sequentially Big George production increase offsets Wyodak decline Powder River Basin Big George Coal Area Exploration & Production

Updated 3P Reserves 3 Tcf 8.5 Tcf 3P '04 YE 7.0 Tcf 37.5% increase in probable and possible reserves Extensive study of Piceance Valley yielded additional 1,600 locations and ~1.5 Tcf probable and possible reserves Rock quality Land/topography Drilling reach H&P rig capabilities provide access to some of the additional locations Does not include Trail Ridge, Ryan Gulch, Red Point and other new areas under Williams' control Exploration & Production '04 YE Proved '04 YE Proved Existing Proved, Prob. & Poss.

Entrance into Ft. Worth Basin Entrance into Ft. Worth Basin Barnett Shale Arkoma Barnett Shale position established: 13,000 net acres Proved reserves of 17 Bcf with 40-50 Bcfe probable and possible High working interest averaging ~90% Utilizes Williams' Mid-continent horizontal drilling expertise Provides numerous bolt-on opportunities Exploration & Production

Dollars in millions Exploration & Production 2005-2007 Hedge Update NEW 4Q only 1 Please note basin locations not NYMEX 2005 2006 2007 Fixed Price: 2nd Half NYMEX Volume (MMcfe/d) 283 299 172 Price ($/Mcfe) $4.48 $4.39 $4.18 Collars : NYMEX Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 $6.62 - $8.42 $6.50 - $8.25 Regional NWPL Rockies1 Volume (MMcfe/d) 50 50 50 Price ($/Mcfe) $6.10 - $7.70 $6.05 - $7.90 $5.65 - $7.45 EPNG San Juan1 Volume (MMcfe/d) 50 Price ($/Mcfe) $5.65 - $7.45

2005 2006 2007 Segment profit $410 - 4851 $520 - 595 $595 - 720 Annual DD&A 235 - 265 295 - 335 365 - 415 Segment profit + DD&A $645 - 750 $815 - 930 $960 - 1,135 Capital spending $605 - 680 $760 - 860 $735 - 885 Production (MMcfe/d) 625 - 700 740 - 840 850 - 950 Unhedged Price Assumption (NYMEX, $/Mcf) $6.34 $5.96 $5.75 Dollars in millions Exploration & Production 2005-2007 Guidance 280 - 320 350 - 400 400 - 475 480 - 555 550 - 675 530 - 605 725 - 825 725 - 875 600 - 700 720 - 820 825 - 925 635 - 740 760 - 875 900 - 1,075 1 Includes YTD nonrecurring adjustments which increase reported earnings by $8 million 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 Note: If guidance has changed, previous guidance from 5/5/2005 is shown in italics directly below

Delivering meaningful volume growth through expanded development drilling activity -- Piceance is primary growth driver Experienced and talented workforce 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 opportunities Trail Ridge, Ryan Gulch, Red Point, Ft. Worth Basin, and Caney Shale Strategy remains rapid development of our premier drilling inventory Key Points Exploration & Production

Midstream Alan Armstrong Senior Vice President

Segment Profit Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Segment Profit $109 $99 $238 $209 Nonrecurring: Devils Tower Revenue Recognition1 (17) (17) Recurring Segment Profit $109 $82 $238 $192 2Q04 to 2Q05 financial highlights include: $16 million - Increase in domestic NGL margins $9 million - Increase in gathering and processing fees $4 million - Increase in production handling fees YTD 2004 to YTD 2005 include: $35 million - Increase in domestic NGL margins $8 million - Increase in domestic NGL volume $12 million - Increase in gathering and processing fees 1 Prior period item Midstream

2nd Quarter and 2005 Accomplishments 2Q05 vs 2Q04: Gathering volumes up 5% Organic Growth: Quintana Mesa Wamsutter Phase 1 Raised $55 million in asset sales 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2004 150 127 172 197 2005 175 155 0 0 Recurring Segment Profit + Depreciation Midstream

2005 2006 2007 Segment Profit $400-470 $400-500 $400-520 Annual DD&A 180-190 185-195 190-200 Segment Profit + DDA $580-660 $585-695 $590-720 Capital Spending $120-140 $110-130 $100-130 Note: If guidance has changed, previous guidance from 5/5/2005 is shown in italics directly below Midstream 2005-2007 Guidance Dollars in millions $370 - $450 Major Growth Projects Not Included Gathering and processing expansions in the West Footprint expansion of deepwater infrastructure $550 - $640

Deepwater Activity Midstream

Key Points Strong earnings and cash flows Raising 2005 segment profit guidance, again Capturing growth opportunities Organic growth around our Western assets Footprint expansion in the deepwater One-two punch Premier assets in growth basins Attracting volumes through reliability Midstream

Gas Pipeline Phil Wright Senior Vice President

Segment Profit Dollars in millions Gas Pipeline Segment Profit $165 $133 $332 $280 Nonrecurring Pension expense reduction1 (17) - (17) - Adjustment to carrying value of certain liabilities1 (5) - (18) - Write-off hydrostatic testing - 9 - 9 Recurring Segment Profit $143 $142 $297 $289 2Q04 to 2Q05 financial highlights include: $3 million - Increased earnings at Gulfstream $(4) million - Grays Harbor contract termination 1 Prior period items

Northwest's 26" Replacement - FERC issues preliminary Order Construction began in July for Central New Jersey expansion project Gulfstream Phase II began flowing volumes under two new long term firm contracts totaling 400MDt/d Transco holds open season for the Potomac Expansion project 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 213 210 211.7 223.9 2005 220.7 208 0 0 Gas Pipeline 2nd Quarter and 2005 Accomplishments

2005 2006 2007 Segment Profit $590 - 6151 $500 - 5652 $585 - 655 Annual DD&A 270 - 280 290 - 300 300 - 310 Segment Profit + DDA $860 - 895 $790 - 865 $885 - 965 Capital Spending $370 - 420 $600 - 700 $250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 5/05/05 is shown in italics directly below Gas Pipeline 1 Includes YTD nonrecurring adjustments which increase reported earnings by $35 million A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams Web site at www.williams.com. 2 Assumes as of 1/1/06 refinancing of $230 million of debt and additional financing of $470 million for Gulfstream ($700 million total) is reflected in these amounts. Impact of Pipeline Safety Improvement Act accounting rule not reflected 555 - 585 835 - 875 280 - 290 475 - 550 565 - 635 865 - 945

2005-2007 Capital Spending Detail $250 - 325 $600 - 700 $370 - 420 Total 70 - 90 10 - 20 20 - 30 2 276 48 $180 - 235 $310 - 400 $305 - 335 Normal Maintenance/ Compliance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion Note: Sum of ranges may not add due to rounding Gas Pipeline 475 - 550 190 - 245

Key Points Another strong quarter; operationally and financially Strong free cash flow generator Increased 2005 guidance due to strong YTD recurring earnings and impacts of prior period items Increased 2007 guidance as higher capital expected to be recovered through rates Guidance not reflective of impact related to accounting ruling on PSIA Continued progress in compliance and reliability projects Expansion development opportunities continue Gas Pipeline

Power Bill Hobbs Senior Vice President

Segment Profit Dollars in millions 2nd Qtr YTD 2005 2004 2005 2004 Gross Margin (Includes MTM) $(35) $72 $105 $71 SG&A (17) (20) (33) (36) Operating & Other Inc. / (Expense) (23) (8) (33) (23) Segment Profit/(Loss) (Includes MTM) $(75) $44 $39 $12 MTM Adjustments 55 (59) (53) 53 Segment Profit/(Loss) After MTM Adjustments $(20) $(15) $(14) $65 Segment Profit/(Loss) (Includes MTM) $(75) $44 $39 $12 Nonrecurring: Expense related to prior period 0 0 8 0 Expense related to Settlements and Litigation Contingencies 13 0 17 0 Recurring Segment Profit/(Loss) $(62) $44 $64 $12 MTM Adjustments 55 (59) (53) 53 Recurring Segment Profit/(Loss) After MTM Adjustments $(7) $(15) $11 $651 Power 1 Includes impact of legacy natural gas portfolio that liquidated in 1Q04.

Power 1 Includes YTD nonrecurring adjustments which decrease reported earnings by $25 million. Power Segment Standalone CFFO would be $25 million higher on a recurring basis. A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com. YTD - Segment Profit to Cash Flow Dollars in Millions Power & Natural Gas Other Total YTD Gross Margin $105 $105 SG&A & Other Inc/(Exp) (66) (66) Segment Profit/(Loss)1 39 0 39 MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (243) (243) Add Realized Gains from MTM previously recognized 190 190 Segment Profit/(Loss) after MTM Adjustments1 (14) 0 (14) Total Working Capital Change 99 99 Power Segment CFFO (14) 99 85 Est. Working Capital Used for Other BU's (55) (55) Power Segment Standalone CFFO ($14) $44 $30

2005 2006 2007 5/05/05 Segment Profit Guidance ($50) - 50 ($250) - (100) ($200) - (50) MTM Earnings (2Q05) 22 Est. Forward Impact of 2Q05 MTM 4 (20) (18) YTD Non-Recurring (25 ) - - Total Impact 1 (20) (18) Change in Segment Profit Guidance - (20) (20) Segment Profit Guidance (50) - 50 (270) - (120) (220) - (70) MTM Adjustments 75 320 270 100 300 250 Reported Segment Profit after MTM Adj 25 - 125 50 - 200 50 - 200 50 - 150 Unchanged Non-Recurring 25 0 0 Recurring Segment Profit after MTM Adj 50 - 150 50 - 200 50 - 200 Unchanged Unchanged Capital Expenditures - - - Dollars in millions 2005-2007 Guidance Power Note: If guidance has changed, previous guidance from 5/05/05 is shown in italics directly below Cash Flow from Operations 50 - 150 50 - 200 50 - 200

Cash Flow Analysis Undiscounted dollars in millions (GAAP Measure) Note: 2Q05 forecast estimated as of 12/30/04. 2Q05 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. The YTD05 forecasted "Merchant Cash Flows" represents both the "Estimated Hedged Tolling Revenues" and "Merchant Cash Flows" in the forecast. Note: Sum of ranges for each business line does not necessarily match total range. Power Combined Power Portfolio Actual v. Forecast 2Q05 Q1'05A Q2'05A Q2'05F YTD05A YTD05F Tolling Demand Payment Obligations ($89) ($99) ($98) ($188) ($188) Resale of Tolling 41 41 33 82 73 Full Requirements (2) 7 7 5 6 Long-term Physical Forward Power Sales 22 21 23 43 44 OTC Hedges 34 38 29 72 70 Estimated Merchant Cash Flows 15 28 42 43 52 Total Cash Flows 21 36 35 57 58 NG & Other Commodity 11 (16) (15) (5) 0 SG&A and Other (26) (40) (18) (66) (36) Working Capital & Other 42 57 (35) 98 22 Estimated Cash Flows 48 37 (34) 85 45 Est. Working Capital Used for Other BU's 13 (68) 0 (55) 0 Power Standalone Cash Flows $61 ($31) ($34) $30 $45

Key Points Recurring results on target CFFO YTD positive and on target Seasonal cash flows - 3rd quarter is historically best quarter for merchant power Full year recurring segment profit guidance remains unchanged Deal flow is increasing Application of FAS133 reduces 2Q05 earnings volatility Market outlook for 2006-2007 improving Power

2005-2007 Consolidated Outlook Don Chappel CFO

Segment profit before MTM adjustment $1,300 - $1,585 $1,275 - $1,575 Net Interest Expense (650) - (670) (630) - (665) Other (Primarily General Corp. Costs) (70) - (100) (80) - (110) Pretax Income 580 - 815 565 - 800 Provision for Income Tax (220) - (335) (235) - (320) Income from Continuing Ops 360 - 480 330 - 480 Income/(Loss) from Discontinued Ops (10) - 0 (10) - 0 Net Income $350 - 480 $320 - 480 Diluted EPS $0.58 - $0.79 $0.53 - $0.80 Recurring Income from Cont. Ops $377 - $497 $326 - $476 Diluted EPS - Recurring $0.62 - $0.82 $0.54 - $0.80 Diluted EPS- Recurring After MTM Adjustments1 $0.70 - $0.90 $0.65 - $0.90 1 Includes MTM adjustment of $75 million (pretax) in Aug 4 guidance and $100 million (pretax) in May 5 guidance Note: Fully diluted shares of 605 million used in Aug 4 guidance and 599 million used in May 5 guidance Dollars in millions, except per-share amounts Aug 4 Guidance Consolidated 2005 Forecast Guidance May 5 Guidance

Dollars in millions 2005-2007 Segment Profit - Reported Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. 20051 2006 Consolidated $410 - 485 400 - 470 590 - 615 (50) - 50 (50) - (35)2 $1,300 - 1,585 75 $1,375 - 1,660 $520 - 595 400 - 500 500 - 565 (270) - (120) 45 - (45) $1,195 - 1,495 320 $1,515 - 1,815 Note: If guidance has changed, previous guidance from 5/5/05 is shown in italics directly below 1 Includes YTD nonrecurring adjustments which decrease reported earnings by $35 million 2 Includes effects of impairments of $53 million 2007 $595 - 720 400 - 520 585 - 655 (220) - (70) 10 - (30) $1,370 - 1,795 270 $1,640 - 2,065 400 - 475 480 - 555 550 - 675 370 - 450 555 - 585 (200) - (50) 1,275 - 1,575 300 250 1,675 1,475 - 1,775 1,575 - 2,000 1,175 - 1,475 1,325 - 1,750 (250) - (100) 565 - 635 0 - 15 100

Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. Reported Consolidated $410 - 485 400 - 470 590 - 615 (50) - 50 (50) - (35) $1,300 - 1,585 75 $1,375 - 1,660 YTD Non-Recurring ($8) - (35) 25 53 $35 - $35 Recurring $402 - 477 400 - 470 555 - 580 (25) - 75 3 - 18 $1,335 - 1,620 75 $1,410 - 1,695 Power After MTM Adj. $25 - 125 $25 $50 - 150 2005 Segment Profit - Recurring Note: Sum of ranges for each business line does not necessarily match total range.

2005 2006 2007 Exploration & Prod. $605 - 680 $760 - 860 $735 - 885 Midstream 120 - 140 110 - 130 100 - 130 Gas Pipeline 370 - 420 600 - 700 250 - 325 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,100 - 1,300 $1,525 - 1,750 $1,100 - 1,300 Dollars in millions Notes: - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 5/5/05 is shown in italics directly below Consolidated 2005-2007 Capital Expenditures 530 - 605 725 - 825 725 - 875 475 - 550 1,025 - 1,225 1,350 - 1,550

1 Includes non-recurring adjustments of $35 million 2 Operating free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 5/5/05 is shown in italics directly below Dollars in millions 2005-2007 Outlook Consolidated Segment Profit1 Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Operating Free Cash Flow2 2005 $1,300 - 1,585 75 $1,375 - 1,660 700 - 775 1,150 - 1,450 1,100 - 1,300 50 - 150 2006 $1,195 - 1,495 320 $1,515 - 1,815 770 - 870 1,550 - 1,850 1,525 - 1,750 25 - 100 2007 $1,370 - 1,795 270 $1,640 - 2,065 840 - 940 1,650 - 1,950 1,100 - 1,300 550 - 650 1,275 - 1,575 100 300 250 1,675 1,475 - 1,775 1,575 - 2,000 1,175 - 1,475 1,325 - 1,750 750 - 850 800 - 900 1,025 - 1,225 1,350 - 1,550 275 - 375 100 - 200 1,300 - 1,600 1,450 - 1,750 1,600 - 1,900 500 - 600

Dollars in millions 2005-2007 Guidance Reconciliation Consolidated Capital Expenditures May 5 Guidance E&P: Ft. Worth Basin Entry / Drilling Gas Pipes: New 2006 Projects Other Misc / Rounding Aug. 4 Guidance 2005 $1,025 - 1,225 75 - - $1,100 - 1,300 2006 $1,350 - 1,550 35 125 - 150 15 $1,525 - 1,750 2007 $1,100 - 1,300 - - - $1,100 - 1,300 Segment Profit 1 May 5 Guidance - Reported E&P: Ft. Worth Basin Entry / Drilling Hedge Collars Midstream: Margins Gas Pipes: New 2006 Projects 2 Q Nonrecurring Items Other Misc / Rounding Aug. 4 Guidance - Reported $1,375 - 1,675 5 5 30 - 20 - (44) 4 - (1) $1,375 - 1,660 $1,475 - 1,775 20 20 - - - - $1,515 - 1,815 $1,575 - 2,000 20 25 - 20 - - $1,640 - 2,065 1 Segment Profit After MTM Adjustment

Dollars in millions 2005-2007 Guidance Reconciliation Consolidated Cash Flow from Operations (CFFO): May 5 Guidance Tax Settlement Reclassification to "Investing"1 E&P Segment Profit Increase Midstream Segment Profit Increase Other Increases - net Aug. 4 Guidance 2005 $1,300 - 1,600 (180) - (200) (88) 10 30-20 78 - 108 $1,150 - 1,450 2006 $1,450 - 1,750 20 - 40 - 40 $1,550 - 1,850 2007 $1,600 - 1,900 25 - 45 - (20) $1,650 - 1,950 1 Contract termination payment previously included in CFFO

Strong Operating Cash Flow Growth & Increasing Investment Opportunities . . . Consolidated 2003 2004 2005 2006 2007 Cap Ex-Low 790 1100 1525 1100 Cap Ex-High 790 1300 1750 1300 CFFO-Low 588 1482 1150 1550 1650 CFFO-High 588 1473 1450 1850 1950 Debt to Cap 0.75 0.623 0.58 0.57 0.54 0.75 0.623 0.59 0.58 0.56 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,473 $1,150 to $1,450 $1,550 to $1,850 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% 58% to 59% 57% to 58% 54% to 56% $1,650 to $1,950 75% $588 $1,100 to $1,300 $1,525 to $1,750 $1,100 to $1,300 $790 Cap Ex Increasing Cash Flow Declining Debt / Cap % Opportunity Rich

Segment Profit Guidance Trend Consolidated 2004 2005 2006 2007 SPAM Low 1263 1375 1515 1640 SPAM High 1263 1660 1815 2065 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1100 1525 1100 Cap Ex-High 790 1300 1750 1300 $ Millions $1,375 to $1,660 $1,515 to $1,815 $1,640 to $2,065 $1,263 (recurring) * Includes MTM adjustments of ($118) in 2004, $75 in 2005, $320 in 2006, and $270 in 2007 Segment Profit After MTM Adjustments * (1-Yr CAGR) 13.6% 14.8% 20.2% (2-Yr CAGR) (3-Yr CAGR)

Drive/enable sustainable growth in EVA(r)/shareholder value Maintain a cash/liquidity cushion of $1.0 billion plus Continue to steadily improve credit ratios/ratings; ultimately achieving investment grade ratios Reduce risk in Power segment Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA-adding opportunities may require new capital If new capital is needed, choose optimal sources of capital Combination of growth in operating cash flows and EVA drives value creation Financial Strategy/Key Points Consolidated

Summary Steve Malcolm Chairman, President & CEO

Hitting on all cylinders Business segment performance Consolidated earnings Cash from operations Growth opportunities growing Growth activity moving key performance measures up Seizing rich opportunities to grow shareholder value Key Points Summary

Q&A

Non-GAAP Reconciliations

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

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

EBITDA Reconciliation 178 DD&A 42 Provision for Income Taxes 163 Net Interest Expense $41 Net Income $423 EBITDA (1) (Income) Loss from Disc. Operations Non-GAAP Reconciliation 2Q05 Dollars in millions YTD $242 1 327 356 171 $1,097

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Total Segment Profit (Loss) $256 DD&A 178 Segment Profit before DDA $434 General Corporate Expense (36) Investing Income* 21 Other Income 4 TOTAL $423 Gas Pipeline $109 46 $155 Corp/Other ($58) ($61) 3 $231 $177 E&P Midstream $165 $118 66 59 $(71) Power $(75) 4 2Q 2005 Segment Contribution Non-GAAP Reconciliation

Net Income $350 - 480 $320 - 480 (Income) Loss from Disc. Ops. 10 - 0 10 - 0 Net Interest 650 - 670 630 - 665 DD&A 700 - 775 700 - 775 Provision for Income Taxes 220 - 335 235 - 320 Other/Rounding - (20) - (15) EBITDA - Reported $1,930 - 2,260 $1,875 - 2,225 MTM Adjustments 75 100 EBITDA - Reported after MTM Adj. $2,005 - 2,335 $1,975 - 2,325 Dollars in millions Consolidated Aug 4 Guidance May 5 Guidance 2005 Forecast EBITDA Reconciliation

2005 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 $(50) - 50 10 - 20 $(40) - 70 Gas Pipeline $590 - 615 270 - 280 $860 - 895 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) TOTAL REPORTED E&P $410 - 485 235 - 265 $645 - 750 Midstream $400 - 470 180 - 190 $580 - 660 Total * $1,300 - 1,585 700 - 775 $2,000 - 2,360 (70) - (100) $1,930 - 2,260 Corp/ Other $(50) - (35) 5 - 20 $(45) - (15) Dollars in millions 1 Segment Profit is on a reported basis and prior to MTM adjustments

Net Income $350 - 480 $320 - 480 Discontinued Operations 10 - 0 10 - 0 Income from Continuing Ops $360 - 480 $330 - 480 Non-Recurring Items (Pretax) 23 (7) Less Taxes @ Approx. 39% (6) 3 Non-Recurring After Tax 17 (4) Recurring Income from Cont. Ops $377 - 497 $326 - 476 Recurring EPS $0.62 - $0.82 $0.54 - $0.80 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 75 (29) 46 $423 - 543 $0.70 - $0.90 100 (39) 61 $387 - 537 $0.65 - $0.90 2005 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts Aug 4 Guidance May 5 Guidance

Appendix

Consolidated EPS $0.34 $0.07 - - $0.41 Recurring EPS 0.33 0.11 - - 0.45 Rec. EPS after MTM Adj. 0.22 0.17 - - 0.39 Average Shares (MM) 599 579 - - 603 2005 1Q 2Q 3Q 4Q Total EPS $0.02 ($0.03) $0.19 $0.13 $0.31 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS Metrics

Interest on Long-Term Debt $575 - 585 Amortization Discount/Premium and other Debt Expense 25 Credit Facilities: (incl. Commitment Fees plus LC Usage) 32 - 40 Interest on other Liabilities 23 - 30 Interest Expense $655 - 680 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $650 - 670 Dollars in millions 2005 Consolidated 2005 Interest Expense Guidance

Drivers Consolidated Dollars in millions Segment (Based on Guidance Midpoints) Profit CFFO 2004 1,381 1 1,473 Interest Savings - 245 Tax Settlement - (200) 2005 Longhorn Impairment (50) - Gas Pipes - Lower Grays Harbor (15) (18) - 2005 Non Recurring Items 41 - - Remove 2004 One Time Gains (9) - Remove 2004 DD&A Adjust. 10 - Gulfstream Higher Firm Transportation 16 - Midstream - Lower NGL Margins (40) - - Deepwater Increase - 40 Changes in Power 2 (75) 100 Margins / Adequacy Assurances - (565) E&P - Price Changes 115 115 - Volume Increases 100 125 Other (32) (15) 2005 1,443 1,300 Interest Savings - 5 Tax Settlement - 200 2005 Longhorn Impairment 50 - Gas Pipes - Remove 2005 Non Recurring Items (41) - - Higher Costs (30) - Changes in Power (195) 25 Midstream - NGL Margins (30) - - Deepwater Increase 80 35 E&P - Price Changes (25) (25) - Volume Increases 135 155 Other (42) 5 2006 1,345 1,700 Interest Savings - 5 Changes in Power 50 - Increase in Gas Pipes 106 111 Midstream - Deepwater Increase 15 15 E&P - Price Changes (50) (50) - Volume Increases 150 170 Other (34) (151) 2007 1,583 1,800 1 Recurring

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 $415 - 470 190 - 210 $605 - 680 60 - 75 60 - 65 $120 - 140 20 - 30 350 - 390 $370 - 420 - $10 - 30 495 - 575 610 - 695 $1,100 - 1,300 $550 - 630 210 - 230 $760 - 860 60 - 75 50 - 55 $110 - 130 10 - 20 590 - 680 $600 - 700 - $10 - 30 620 - 725 860 - 995 $1,525 - 1,750 $505 - 635 230 - 250 $ 735 - 885 50 - 70 50 - 60 $100 - 130 70 - 90 180 - 235 $250 - 325 - $10 - 30 625 - 795 470 - 575 $1,100 - 1,300 2005 2006 2007 Consolidated

2005 Effective Tax Rates Dollars in millions Consolidated FIrst Quarter 2005 Federal 115 35% State 14 4% Foreign (5) -2% Other 5 2% Tax Provision 129 $ 39% Second Quarter 2005 Federal 29 35% State 1 3% Foreign 5 6% Other 7 7% Tax Provision 42 $ 51% Year-to-Date 2005 Federal 145 35% State 16 4% Foreign 0 0% Other 10 2% Tax Provision 171 $ 41% Effective Tax Rate Guidance 1 Cash Tax Rate Guidance 2 Note 1: An additional $25 million income tax expense is forecast in 2006 & 2007. Note 2: We have reached preliminary settlement with the Internal Revenue Service relating to an outstanding tax issue associated with prior years. As a result of the preliminary settlement, we expect to make a payment totaling approximately $180-$200 million in the last half of 2005, all of which is accrued at June 30, 2005. The expected settlement is subject to the approval of the Joint Committee on Taxation. Note 3: Discontinued operations in 2005 have less than $1 million tax impact. 3-5% 4-8% 5-10% 2005 See Above 2006 39% Continuing Operations 3 2007 39%

2Q 2005 Net Realized Price Calculation Exploration & Production 2Q05 Unhedged Hedge Market Price: NYMEX including collars $6.60 - $6.80 $4.60 Basis Differential (0.50 - 0.70) (0.48) Net basin market price $5.90 - $6.30 $4.12 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $4.90 - $5.50 $3.12 - $3.32 Quarter Volume Totals (qtr daily volumes (qtr daily qtr daily hedged volumes) hedge volumes) x (91/1000) x (91/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price)

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 2nd Half 2005 2005 Unhedged Hedge Market Price: NYMEX $6.10 - $6.50 $4.48 Basis Differential (0.50 - 0.70) (0.45) Net basin market price $5.40 - $6.00 $4.03 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $4.40 - $5.20 $3.03 - $3.23 Year Volume Totals (Bcfe) (total daily vols (daily hedge - daily hedge vols) volumes) x x (183/1000) (183/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price)

Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2000-2004. Midstream Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) 0 5 10 15 20 25 Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Q1'05 Q2'05 0 100 200 300 400 500 600 700 Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin

Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 718 812 823 Commodity 301 237 200 200 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% 25% 21% 20% 75% 79% 80%

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

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

Margins & Ad. Assur. $6 - $53 - $59 Prepayments - 1 34 - 35 Subtotal $6 $1 $87 - $94 Letters of Credit 469 183 270 92 1,013 Total as of 6/30/05 $475 $184 $357 $92 $1,107 Total as of 3/31/05* $566 $169 $311 $90 $1,136 Change ($91) $15 $46 $2 ($29) Corp./ E&P Midstream Power Other Total Dollars in millions As of 6/30/05 *Note: The allocation of LC's between business units as of 3/31 has been adjusted from that previously reported. Total 3/31/05 LC's reported is unchanged. WMB Collateral Outstanding

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