Exhibit 99.2

Williams 2005 1st Quarter Earnings Release May 5, 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

Headlines Williams delivers strong 1Q performance Midstream benefits again from above average margins, strong volumes Exploration & Production boosts year-over- year production Gas Pipeline posts another solid quarter Power continues to deliver positive cash flow Strength in consolidated cash flows continues Overview

Headlines Williams seizes rich opportunities for growth Picking up the pace to grow Piceance production Expanding pipelines to meet market demand Pursuing deep-water infrastructure opportunities Contracting existing power capacity Business overview set for May 12 Power Gas Pipeline E&P Overview

Headlines Williams Partners L.P. files registration statement $270 million expected initial enterprise value 100% equity capitalization at IPO 3Q expected completion Williams ownership 2% General Partner Interest 61% Limited Partner Interest $85 million cash to Williams expected at closing Williams would receive minimum quarterly distribution of $3.1 million per quarter Williams to account for partnership on consolidated basis Note: All dollar amounts on this page are approximate. Overview

MLP Foundation Assets Discovery 40% interest Integrated wellhead-to-market midstream services for Gulf of Mexico producers Offshore gathering and transportation system with 600 MMcf/d capacity Onshore gas processing and fractionation facilities Carbonate Trend Pipeline Sour-gas gathering pipeline offshore Alabama 120 MMcf/d capacity Conway Storage Largest storage facility at main trading hub in Midcontinent Approximately 20 million bbls storage for multiple NGL products Direct connectivity into Mid-America Pipeline Conway Fractionator 50% interest in fractionator adjacent to storage facility Share of capacity is 53,500 bbl/d Williams Partners L.P.

MLP Benefits to Williams Gain access to new, lower cost source of equity capital Receive premium valuation for assets Retain control of monetized assets Redeploy IPO proceeds Create Economic Value Added(r) Deliver WMB shareholders increased equity value Williams Partners L.P.

2005 Financial Results Don Chappel, CFO

1st Quarter 2005 2004 Income from Continuing Operations $202 $0 Income (Loss) from Disc. Operations (1) 10 Net Income $201 $10 Net Income/Share $0.34 $0.02 Recurring Inc. from Cont. Ops. /Share $0.33 $0.01 Recurring Inc. from Continuing Ops. After MTM Adjustments/Share $0.22 $0.14 Financial Results Dollars in millions (except per share amounts) 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.

2005 2004 Income from Continuing Operations $202 $0 Gains on Sale of Assets (8) - Income Related to Prior Periods (6) - Other - Net 7 7 Tax effect of adjustments 3 (3) Recurring Inc. from Cont. Ops. Avail. to Com. $198 $4 Recurring Income from Cont. Ops./Share $0.33 $0.01 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. 1st Quarter Consolidated

Recurring Income from Cont. Ops. After Mark-to-Market Adjustments Consolidated 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 Recurring Diluted Earnings per Common Share Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM gains Total MTM adjustments Tax effect of total MTM adjustments (at 39%) Recurring income from Continuing Operations avail. to Common Shareholders after MTM adjustments Recurring Diluted Earnings per share after MTM adjustments After-tax MTM adjustments Add realized gains from MTM previously recognized 1st Quarter 2005 198 $ 0.33 $ (221) (108) 42 132 $ 0.22 $ (66) 113 2004 4 $ 0.01 $ (24) 112 (44) 73 $ 0.14 $ 69 136

2005 2004 Segment Profit $510 $268 Net Interest Expense (164) (239) Other Income/(Expense) - Net (14) (17) Income from Cont. Ops. Before Tax 332 12 Provision for Income Tax 130 12 Income/(Loss) from Continuing Ops. $202 $0 Income/(Loss) from Discontinued Ops. (1) 10 Net Income $201 $10 Net Income Components Dollars in millions (except per share amounts) 1st Quarter Consolidated

First Quarter Segment Profit Reported Recurring 1Q05 1Q04 1Q05 1Q04 Exploration & Production $104 $52 $96 $52 Midstream Gas & Liquids 129 110 129 110 Gas Pipeline 167 147 154 147 Power 114 (32) 125 (32) Other (4) (9) (4) (2) Segment Profit $510 $268 $500 $275 MTM Adjustments - Power (108) 112 Segment Profit after MTM Adjustments $392 $387 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.

Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 1Q04 $387 Exploration & Production 44 - Higher production volumes +$16 million - Higher net realized price +$36 million Midstream 19 - Increased NGL margins +$19 million - Increased NGL volume +$7 million - Improved olefins results +$6 million - Increased O&M -6 million Gas Pipeline 7 - Increased Gulfstream earnings +$3 million - Gulfstream completion fee +$5 million Power (63) - Lower realized gains in natural gas portfolio - $91 million - Absence of realized losses on interest rate portfolio +$31 million Other (2) Recurring Segment Profit after MTM Adj. 1Q05 $392 Dollars in millions

1Q05 Beginning Unrestricted $930 Cash flow from Continuing Operations 304 Proceeds from Issuing Common* 288 Sale of WilTel Note 54 Contract Termination Payment 88 Debt Retirements (216) Capital Expenditures/Investments (223) Dividends (29) Other-Net 14 Ending Unrestricted Cash at 3/31/05 $1,210 Restricted Cash at 3/31/05 (not included above) $83 Cash Information Dollars in millions Consolidated * $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS

Debt Balance Debt Balance @ 12/31/04* $7,962 7.4% Scheduled Debt Retirements & Amortization (216) Capitalized Lease 4 Debt Balance @ 3/31/05* $7,750 7.4% Fixed Rate Debt @ 3/31/05 $7,094 7.7% Variable Rate Debt @ 3/31/05 $656 5.0% Avg. Cost * Debt is long-term debt due within 1 year plus long-term debt plus notes payable. Dollars in millions Consolidated

Business Unit Results

Exploration & Production Ralph Hill, Senior Vice President

1st Quarter 2005 2004 Segment Profit Dollars in millions Segment Profit $104 $52 Nonrecurring: Gain on sale of assets (8) - Recurring Segment Profit $96 $52 Exploration & Production 1Q04 to 1Q05 financial highlights include: Volume increase of 22% Net realized price increase of 31% Recurring profit increase of 88% Base business sequential quarter improved Recurring profit increased 28% Volumes increased by 1.5%, despite unprecedented winter weather $36 million negative hedge impact in 1Q05

Strong Domestic Production Growth Exploration & Production 2004 2005 400 500 600 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Net MMcfed

2005 Accomplishments 1Q05 production up 22%, 113 MMcfed since 1Q04 Piceance production up 59% since 1Q04 Piceance higher activity, 10 new H&P rigs contracted Additional Piceance 10-acre spacing approved Trail Ridge/Ryan Gulch additional drilling this year Big George volumes continue to increase San Juan production up 13% since 1Q04 Arkoma Caney shale position expanded Exploration & Production

2005 2006 2007 Segment profit $400 - 475 $480 - 555 $550 - 675 Annual DD&A 235 - 265 280 - 320 350 - 400 Segment Profit + DD&A $635 - 740 $760 - 875 $900 - 1,075 Capital spending $530 - 605 $725 - 825 $725 - 875 Production (MMcfe/d) 600 - 700 720 - 820 825 - 925 Hedges (NYMEX Equivalent) Fixed Price: Volume (MMcfe/d) 283 298 172 Price ($/Mcfe) $4.44 $4.39 $4.20 Collar: Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 2Q-YE $6.62 - $8.42 $6.50 - $8.25 Dollars in millions Exploration & Production 2005-2007 Guidance Note: Guidance (except DD&A) was updated in the 3/23/05 press release regarding accelerated drilling program. Changes in DD&A are shown in italics directly below 220 - 250 250 - 290 300 - 350

Key Points Exploration & Production Achieving strong volume growth Continuing to expand development drilling activity - Piceance is primary growth driver 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 Strategy remains rapid development of our premier drilling inventory

Midstream Alan Armstrong, Senior Vice President

1st Quarter 2005 2004 Segment Profit $129 $110 Nonrecurring: - - Recurring Segment Profit $129 $110 Dollars in millions 1Q04 to 1Q05 financial highlights include: $19 million increase in NGL margins $7 million increase in NGL volume $6 million due to better performance in Olefins $(6) million increased O&M expense $(4) million Canyon Station outage Midstream Segment Profit

1st Quarter and 2005 Accomplishments Three key operating statistics up: Gathering volumes up 3% Processing volumes up 3% NGL sales volumes up 22% Two new Letters of Intent executed for Deepwater Acquired ENI's interest in Discovery Gulf Liquids sale, 2Q05 S-1 for Williams Partners L.P. * 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 2004 150 128 172 197 2005 178 0 0 0 Recurring Segment Profit + Depreciation* Midstream

2005 2006 2007 Segment Profit $370-450 $400-500 $400-520 Annual DD&A 180-190 185-195 190-200 Segment Profit + DDA $550-640 $585-695 $590-720 Capital Spending $120-140 $110-130 $100-130 Note: - Guidance does not include any new major deepwater capital projects - If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below Midstream 2005-2007 Guidance Dollars in millions $350 - $430

Key Points Raising 2005 guidance, again Strong demand for services is yielding Higher key operating statistics High return organic growth opportunities Continued strong free cash flows Deepwater expansion continues One-two punch Premier assets in growth basins Attracting volumes through reliability Midstream

Gas Pipeline Phil Wright, Senior Vice President

Segment Profit $167 $147 Nonrecurring: Expense reduction related to prior period* (13) - Recurring Segment Profit $154 $147 1Q04 to 1Q05 financial highlights include: $5 million - Gulfstream completion fee $3 million - Increased earnings at Gulfstream Segment Profit 1st Quarter 2005 2004 Dollars in millions Gas Pipeline * Reflects reversal of transportation and exchange liabilities and certain other liabilities recorded in prior periods

Transco sets three-day delivery record in January Gulfstream Phase II placed into service FERC approves the Central New Jersey project Leidy to Long Island project - agreement executed with KeySpan Transco and Northwest receive top ranking by the Mastio & Co. customer survey in their respective regions 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 208 208 211.7 223.9 2005 220.7 0 0 0 Gas Pipeline 1st Quarter and 2005 Accomplishments

2005 2006 2007 Segment Profit (1) $555 - 585 $500 - 565 $565 - 635 Annual DD&A 280 - 290 290 - 300 300 - 310 Segment Profit + DDA $835 - 875 $790 - 865 $865 - 945 Capital Spending $370 - 420 $475 - 550 $250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below Gas Pipeline 1 Reflects termination of Gray's Harbor contract in 1Q05 2 Assumes 1/1/06 refinancing of $250 million of debt and additional financing of $350 million for Gulfstream. 545 - 585 825 - 875 515 - 565 575 - 635 875 - 945 805 - 865 (2) (2)

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

Key Points Another strong quarter, operationally and financially Strong free cash flow generator Achieving substantial progress in operational compliance and reliability projects Continued success in... Customer satisfaction Expansion development System operations Gas Pipeline

Power Bill Hobbs, Senior Vice President

Gross Margin $140 ($2) SG&A (16) (16) Op. & Other Inc / (Expense) (10) (14) Segment Profit $114 $(32) Nonrecurring: Expense related to prior period and other 11 - Recurring Segment Profit 125 (32) MTM Adjustments (108) 112 Recurring Segment Profit after MTM Adjustments $17 $80 1st Quarter 2005 2004 Segment Profit Dollars in millions Power

Segment Profit to Cash Flow Power Dollars in millions Power & Natural Gas Other Total Gross Margin $140 $140 SG&A & Other Inc/(Exp) (26) (26) Segment Profit $114 $0 $114 MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (221) (221) Add Realized Gains from MTM previously recognized 113 113 Segment Profit after MTM Adjustments $6 $0 $6 Total Working Capital Change 42 42 Power Segment CFFO $6 $42 $48 Est. Working Capital Used for Other BU's 13 13 Power Segment Standalone CFFO $6 $55 $61

2005 2006 2007 2/23/05 Segment Profit Guidance ($250) - (150) ($200) - (50) ($100) - 50 1st Quarter 2005 Impact: MTM Earnings 221 Est. Forward Impact of MTM (32) (54) (92) Total 1st Quarter 2005 Impact 189 (54) (92) Change in Segment Profit Guidance 200 (50) (100) Revised Segment Profit Guidance ($50) - 50 ($250) - (100) ($200) - (50) MTM Adjustments* 100 300 250 300 250 150 Segment Profit after MTM Adjustments* 50 - 150 50 - 200 50 - 200 Unchanged Cash Flow from Operations* 50 - 150 50 - 200 50 - 200 Unchanged Capital Expenditures - - - Dollars in millions - 2005-2007 Guidance Power * If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below -

Key Points Positive CFFO in a shoulder quarter CFFO expected to remain positive Risk reducing contracts term sales are occurring Expect to see improvements Market liquidity Spark spreads Williams credit Active E&P drilling program will increase natural gas 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

Segment profit before MTM adjustment $1,275 - 1,575 $1,050 - 1,350 Net Interest Expense (630) - (665) (625) - (660) Other (Primarily General Corp. Costs) (80) - (110) (90) - (125) Pretax Income 565 - 800 335 - 565 Provision for Income Tax (235) - (320) (155) - (245) Income from Continuing Ops 330 - 480 180 - 320 Income/(Loss) from Discontinued Ops (10) - 0 (5) - 5 Net Income $320 - 480 $175 - 325 Diluted EPS $0.53 - $0.80 $0.31 - $0.57 Recurring Income from Cont. Ops $326 - 476 $180 - 320 Diluted EPS - Recurring $0.54 - $0.80 $0.31 - $0.56 Diluted EPS - Recurring After MTM Adjustments(1) $0.65 - $0.90 $0.63 - $0.88 (1) Includes MTM adjustments of $100 million (pretax) in May 5 Guidance and $300 million (pretax) in Feb. 23 Guidance Dollars in millions, except per-share amounts May 5 Guidance Consolidated 2005 Forecast Guidance Feb 23 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 Consolidated $400 - 475 370 - 450 555 - 585 (50) - 50 0 - 15 $1,275 - 1,575 100 $1,375 - 1,675 $480 - 555 400 - 500 500 - 565 (250) - (100) 45 - (45) $1,175 - 1,475 300 $1,475 - 1,775 350 - 430 515 (250) - (150) 5 - 10 35 - (40) Note: If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below 1,050 - 1,350 $1,450 - 1,750 300 (200) - (50) 250 545 $1,350 - 1,650 1,200 - 1,500 450 - 525 2007 $550 - 675 400 - 520 565 - 635 (200) - (50) 10 - (30) $1,325 - 1,750 250 $1,575 - 2,000 (100) - 50 0 150 $1,525 - 1,950 575 500 - 625 1,375 - 1,800

(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 2/23/05 is shown in italics directly below Dollars in millions 2005 - 2007 Outlook Consolidated 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 2005 $1,275 - 1,575 100 1,375 - 1,675 700 - 775 1,300 - 1,600 1,025 - 1,225 275 - 375 39% 3 - 5% 300 1,050 - 1,350 1,000 - 1,200 300 - 400 1,350 - 1,650 2006 $1,175 - 1,475 300 1,475 - 1,775 750 - 850 1,450 - 1,750 1,350 - 1,550 100 - 200 39% 4 - 8% 1,150 - 1,350 300 - 400 250 1,450 - 1,750 1,200 - 1,500 2007 $1,325 - 1,750 250 1,575 - 2,000 800 - 900 1,600 - 1,900 1,100 - 1,300 500 - 600 39% 5 - 10% 900 - 1,100 700 - 800 150 1,525 - 1,950 1,375 - 1,800

2005 2006 2007 Exploration & Prod. $530 - 605 $725 - 825 $725 - 875 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 $1,025 - 1,225 $1,350 - 1,550 $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 2/23/05 is shown in italics directly below Consolidated 2005 - 2007 Capital Expenditures $1,150 - 1,350 $900 - 1,100 $1, 000 - 1,200 525 - 625 525 - 675 500 - 575

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 $340 - 395 190 - 210 530 - 605 60 - 75 60 - 65 120 - 140 20 - 30 350 - 390 370 - 420 - 10 - 30 420 - 500 610 - 695 $1,025 - 1,225 $515 - 595 210 - 230 725 - 825 60 - 75 50 - 55 110 - 130 10 - 20 465 - 530 475 - 550 - 10 - 30 585 - 690 735 - 845 $1,350 - 1,550 $495 - 625 230 - 250 725 - 875 50 - 70 50 - 60 100 - 130 70 - 90 180 - 235 250 - 325 - 10 - 30 615 - 785 470 - 575 $1,100 - 1,300 2005 2006 2007 Consolidated

Steady Improvement . . . 2004 2005 2006 2007 CFFO-Low 1482 1300 1450 1600 CFFO-High 1473 1600 1750 1900 Debt to Cap 0.623 0.58 0.57 0.54 0.623 0.59 0.58 0.56 Cash Flow 1 Debt / Cap 2 Increasing Cash Flow $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% 58% to 59% 57% to 58% Decreasing Debt / Cap % 54% to 56% $1,600 to $1,900 Consolidated

Guidance Trends 2004 2005 2006 2007 SPAM Low 1263 1375 1475 1575 SPAM High 1263 1675 1775 2000 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1025 1350 1100 Cap Ex-High 790 1225 1550 1300 $1,025 to $1,225 $1,350 to $1,550 $1,100 to $1,300 $ Millions $790 $1,375 to $1,675 $1,475 to $1,775 $1,575 to $2,000 $1,263 (recurring) * Includes MTM adjustments of ($118) in 2004, $100 in 2005, $300 in 2006, and $250 in 2007 Consolidated Segment Profit After MTM Adjustments * Cap Ex

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

Hitting on all cylinders Another strong quarter Raising earnings guidance Seizing rich opportunities to grow shareholder value Williams Partners L.P. files registration statement Business overview on May 12 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 130 Provision for Income Taxes 164 Net Interest Expense $201 Net Income $674 EBITDA 1 Loss from Disc. Operations Non-GAAP Reconciliation 1Q05 Dollars in millions

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Total Segment Profit (Loss) $510 DD&A 179 Segment Profit before DDA $689 General Corporate Expense (28) Investing Income* 13 Other Income - TOTAL $674 Gas Pipeline $129 46 $175 Corp/Other ($1) ($4) 3 $234 $163 E&P Midstream $167 $104 67 59 $118 Power $114 4 1Q 2005 Segment Contribution Non-GAAP Reconciliation

Net Income $320 - 480 $175 - 325 Income (Loss) from Disc. Ops. 10 - 0 5 - (5) Net Interest 630 - 665 625 - 660 DD&A 700 - 775 700 - 775 Provision for Income Taxes 235 - 320 155 - 245 Other/Rounding (20) - (15) (10) - 0 EBITDA - Reported & Recurring $1,875 - 2,225 $1,650 - 2,000 MTM Adjustments 100 300 EBITDA after MTM Adj. $1,975 - 2,325 $1,950 - 2,300 Dollars in millions 2005 Forecast EBITDA Reconciliation Consolidated May 5 Guidance Feb 23 Guidance

Power * (50) - 50 10 - 20 (40) - 70 Gas Pipeline 555 - 585 280 - 290 835 - 875 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) TOTAL RECURRING E&P 400 - 475 235 - 265 635 - 740 Midstream 370 - 450 180 - 190 550 - 640 Total * 1,275 - 1,575 700 - 775 1,975 - 2,350 (100) - (125) 1,875 - 2,225 Corp/ Other 0 - 15 (5) - 10 (5) - 25 2005 Forecast Segment Contribution Non-GAAP Reconciliation 350 - 430 (250) - (150) 5 - 10 1,050 - 1,350 220 - 250 10 - 25 620 - 725 530 - 620 (240) - (130) 15 - 35 1,750 - 2,125 1,650 - 2,000 545 825 Dollars in millions * Segment Profit is on a reported basis and prior to MTM adjustments

Net Income $320 - 480 $175 - 325 Less: Discontinued Operations 10 - 0 5 - (5) Income from Continuing Ops $330 - 480 $180 - 320 Non-Recurring Items (Pretax) (7) - Less Taxes @ 39% 3 - Non-Recurring After Tax (4) - Recurring Income from Cont. Ops $326 - 476 $180 - 320 Recurring EPS $0.54 - $0.80 $0.31 - $0.56 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 100 (39) 61 $387 - 537 $0.65 - $0.90 300 (117) 183 $363 - 503 $0.63 - $0.88 2005 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts May 5 Guidance Feb 23 Guidance

Appendix

EPS Metrics Consolidated EPS $0.34 - - - Recurring EPS 0.33 - - - Rec. EPS after MTM Adj. 0.22 - - - Average Shares (MM) 599 - - - 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

Interest on Long-Term Debt $560 - 580 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 $635 - 675 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $630 - 665 2005 Interest Expense Guidance Dollars in millions 2005 Consolidated

Drivers Consolidated Dollars in millions

2005 Effective Tax Rate Combined Continuing Ops. Disc. Ops. First Quarter 2005 Federal $115 35% $116 35% $(1) 35% State 14 4% 14 4% * 3% Foreign (5) (2%) (5) (2%) - 0% Other 5 5% 5 2% - 0% Tax Provision $129 39% $130 39% ($1) 38% Dollars in millions Consolidated * Rounding - less than .1 million benefit

1Q 2005 Net Realized Price Calculation Exploration & Production 1Q05 Unhedged Hedge Market Price: NYMEX including collars $6.20 - $6.30 $4.59 Basis Differential (0.50 - 1.00) (0.49) Net basin market price $5.30 - $5.70 $4.10 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $4.50 - $4.70 $3.10 - $3.30 Quarter Volume Totals (qtr daily volumes (qtr daily qtr daily hedged volumes) hedge volumes) x (90/1000) x (90/1000) 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

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 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 15.03 Volume (MM Gallons) 292 296 333 271 300 199 228 298 327 328 373 400.5 399 Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Actual Margin shown for 2000 - 2004. Midstream Margins Above Average Domestic NGL Actual Average Net Margin and Volume by Quarter Margin (Cents / Gallon) Equity Volume by Quarter (MM Gallons) Avg Margin

Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 755.6 799 823 Commodity 301 227 207.7 210 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% 23% 21% 20% 77% 79% 80%

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

Cash Flow Variance Analysis Undiscounted dollars in millions Note: 1Q05 forecast estimated as of 12/30/04. 1Q05 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

Enterprise Risk Management Margins & Ad. Assur. $70 $1 $87 - $158 $134 Prepayments - 4 27 - 31 40 Subtotal $70 $5 $114 $ - $189 $174 Letters of Credit 496 104 257 90 947 855 Total as of 3/31/05 $566 $109 $371 $90 $1,136 $1,029 Total as of 12/31/04 $449 $135 $350 $95 $1,029 Change $117 ($26) $21 ($5) $107 Corp./ 12/31/04 E&P Midstream Power Other Total Total Dollars in millions As of 3/31/05

Enterprise Risk Management Margin volatility (99% confidence interval) - Incremental liquidity requirement 3/31/05 12/30/04 30 days ($124) ($106) 180 days ($328) ($268) 360 days ($341) ($353) Assumption: The margin numbers above consist of only the forward marginable position values, starting from May 2005. Dollars in millions