8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): May 12, 2005

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1-4174	73-0569878
(State or other	(Commission	(I.R.S. Employer
jurisdiction of	File Number)	Identification No.)
incorporation)

One Williams Center, Tulsa, Oklahoma	74172
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 918/573-2000

Not Applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240-14a-12)

o  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01. Other Events.

      Williams wishes to disclose for Regulation FD purposes its slide presentation, furnished herewith as Exhibit 99.1, to be utilized during a public conference call and webcast on the morning of May 12, 2005.

      The slide presentation is being furnished pursuant to Item 8.01, Other Events. The information furnished is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 9.01.	Financial Statements and Exhibits.
(a)	None
(b)	None
(c)	Exhibits
	Exhibit 99.1	Copy of Williams’ slide presentation to be utilized during the May 12, 2005, public conference call and webcast.

      Pursuant to the requirements of the Securities Exchange Act of 1934, Williams has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	THE WILLIAMS COMPANIES, INC.
Date: May 12, 2005	/s/ Brian K. Shore
	Name:	Brian K. Shore
	Title:	Corporate Secretary

2

INDEX TO EXHIBITS

EXHIBIT
NUMBER	DESCRIPTION
Exhibit 99.1	Copy of Williams’ slide presentation to be utilized during the May 12, 2005, public conference call and webcast.

3

EX-99.1

EXHIBIT 99.1

Williams Business Update Steve Malcolm, President and CEO May 12, 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.

Power Update Bill Hobbs, Senior Vice President Power May 12, 2005

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 1Q05 Earnings Call Power

Today's Discussion Brief overview of natural gas operations Discuss executed power sales Regional outlook Threats to competitive markets Q&A Power

Natural Gas Power

Physical Natural Gas Average annual requirements 2.5 Bcf/d with peak of 3.0 Bcf/d 60% for Power 30% power-plant supply 70% third-party transactions 40% for Williams' core businesses Transportation 2.5 Bcf/d 50% for gas marketing (including power-generation fuel) 50% for Williams' core businesses Storage 13 Bcf 50% for gas marketing (including power-generation fuel) 50% for Williams' core businesses Power

Power Power

Types of Sales Around Tolling Deals From Most Effective to Least Effective Type of Sale Resale of tolling Heat-rate sales Full requirements Capacity sales Forward fixed-price sales How It Works Williams buys tolling rights for a certain dollar amount per kilowatt-year and sells similar or "mirror-image" rights to another party for a larger amount per kilowatt- year. Example: CDWR Product D. Williams sells for a certain dollar amount per kilowatt- year a heat-rate option (a right to energy priced using a heat-rate) and valued at a smaller amount per kilowatt-year. Williams serves load of an entity, usually at a fixed price, using production from other Williams assets and/or the entity's resources. Examples: EMC and Allegheny Co-op contracts. Generation capacity rights, generally sold on a $/kW- yr or $kW-month basis; but markets and definitions vary. Blocks of power (energy) sold on a fixed-price or heat- rate basis. Examples: CDWR A, B, C. Power

Recent Successes $32 Million EVA to Date on Deals West Partial resale or toll, plus gas sale 2006-2008 Heat-rate option sale 2008 Summer "capacity" sale (contractually-defined rights) 2005 Approx. cumulative 1250 MW total over 2005-2008 period Mid-Continent 170-MW forward energy sale from CLECO position for June-Sept 2005 Northeast 100-MW heat-rate option sale to municipality for June 2005-May 2006 Currently evaluating 10 transactions with terms ranging from 1 to 10 years Power

Overview of West Capacity: 4,141 MW* Base term: June 2013 5-year option for either party to extend to 2018 Annual demand payment: $153 million in 2004-05 Escalates 1.0% annually until 2013; flat after 2013 Variable O&M payment $2.30/MWh in 2005 Annual escalator is lesser of 2.5% or CPI CDWR sales more than cover demand payments through 2010 Owned: Milagro 60 MW Natural-gas fired Tolling: AES 4000 4,141 MW Through 2018 Forward Power Sale: CDWR A, B, C 50-450 MW Through 2010 Resale of Toll: CDWR D 1,045-1,175 MW Through 2010 * Receiving non-availability payments for 266 MWs that have been retired Power

Market Outlook in West Market outlook Southern California remains tight on capacity and energy California Energy Commission report shows declining reserve margins in SP-15 through 2009 Financial players entering market need physical supply Development of capacity market should enhance Williams' position in later years Schwartzenegger administration promoting competitive market solutions Regulatory activity California Public Utilities Commission promoting resource adequacy, competitive procurement and capacity market California Independent System Operator tariff redesign inches forward with regard to development of capacity markets and locational marginal pricing Power

Overview of Mid-Continent Tolling agreements 1,306 MW 7,700 average heat rate Accounts for approximately 22% of approximately $400 million annual demand charges Tolling: Cleco Evangeline 765 MW Through 2020 Forward Heat Rate Sale: Cleco Evangeline 170 MW Summer 2005 Tolling: Kinder Morgan - Jackson 541 MW Through 2018 Power

Market Outlook in Mid-Continent Market outlook Overbuilt in the South with transmission constraints Midwest Independent System Operator (MISO) energy- market implementation and future capacity-market development should increase KM-Jackson value Was active in the Cleco RFP process Industry data suggests supply/demand equilibrium post- 2010 for both MISO and SERC-Entergy areas Power

Market Outlook in Mid-Continent Regulatory activity - Cleco Entergy introduces independent transmission coordinator (ITC) proposal with Southwest Power Pool as administrator Louisiana commission completes retirement study and identifies significant savings associated with elimination of old plants Regulatory activity - KM-Jackson MISO has provided transmission operations services since Feb. 2005 Commenced operation in April 2005 of energy markets with economic dispatch and locational marginal pricing Efforts underway to introduce capacity markets and ancillary services by 2006 Power

Overview of the East Tolling agreements 2,276 MW; 7,000 average heat rate Accounts for approximately 40% of approximately $400 million annual demand charges Georgia EMCs and Allegheny can be supplied by Tenaska and Ironwood, respectively Full Requirements: Allegheny Electric Co-op 515-600 MW Through 2008 Tolling: AES Ironwood 666 MW Through 2021 Tolling: AES Red Oak 766 MW Through 2022 Owned: Hazleton 147 MW Natural gas-fired Full Requirements: Four Georgia EMCs 600-1,500 MW Through 2015 Tolling: Tenaska Lindsay Hill 844 MW Through 2020 Power

Market Outlook in Northeast Market outlook Transmission congestion over last year increased Red Oak run time Capacity-market redesign expected to enhance Red Oak, Ironwood values Locational capacity values expected to benefit eastern PJM first Industry data suggests supply/demand equilibrium around 2008 Regulatory activity PJM expanding westward and southward adds new markets and improves liquidity Market deemed competitive by market monitor Capacity-market redesign encountering near-term obstacles Capacity costs at all-time low Redesign could send stronger, earlier price signals Recognition of locational value of capacity is critical Potential delay of capacity market redesign implementation until 2007 Power

Potential Threats to Competitive Markets Utility self-build despite existing capacity Greater threat to those building new plants Competitive solicitation levels playing field Price mitigation continues to undermine competition Utilize uncommitted capacity for reliability needs at below-fair-market value (cost-based rates) Mutes appropriate price signals Provides dis-incentive for new investment Short-term solution to longer term structural imbalance Lack of active capacity markets does not reflect appropriate value for assets/location and limits appetite for new investment Power

Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Note: Est. NG Portfolio Cash Flows represent expected cashflows from NG Storage, Transport and hedges. Power Estimated Total Cash Flows Undiscounted dollars in millions Combined Power Portfolio Estimated as of 3/31/05 Q1A 2005A+F 2006F 2007F 2008-2010F 2011-2022F Tolling Demand Payment Obligations ($89) ($368) ($402) ($406) ($1,233) ($3,868) Resale of Tolling $41 $126 $106 $96 $158 $0 Full Requirements ($2) $3 ($7) $0 $6 $26 Long-term Physical Forward Power Sales $22 $25 ($13) ($1) $29 $0 OTC Hedges $34 $146 $205 $66 $107 $58 Estimated Hedged Tolling Revenues $15 $184 $279 $283 $588 $279 Subtotal $21 $116 $168 $38 ($345) ($3,505) Estimated Merchant Cash Flows $0 $79 $28 $156 $873 $5,850 Est. Combined Power Portfolio Cash Flows $21 $195 $196 $194 $528 $2,345 Est. NG Portfolio Cash Flows $11 ($14) $1 $5 $70 ($63) SG&A and Other ($26) ($81) ($73) ($75) ($225) ($800) Subtotal $6 $100 $124 $124 $373 $1,482 Working Capital and Other $42 $23 $1 $3 $6 $103 Estimated Cash Flows After SG&A $48 $123 $125 $127 $379 $1,585 Capacity Available (in MW) 5,149 7,723 7,723 7,723 7,723 Expected Output (in MW) 1,533 2,289 2,530 2,917 3,479 Total Volume Hedged (in MW) 1,451 1,977 1,867 1,172 136 Percentage Volume Hedges 95% 91% 73% 40% 5%

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 - 1Q05 Earnings Call

Q&A Questions? Power

Gas Pipeline Update Phil Wright, Senior Vice President Gas Pipeline May 12, 2005

Quality Assets Serving Growth Markets Gulfstream (50% Ownership) Underground storage LNG peaking facility Transco Northwest Gas Pipeline

Strategy Overview Strategic Objective Maximize utilization of pipeline system capacity Provide high quality, low cost services Maintain access to supplies and markets Customer Value Proposition Reliable service Low cost Gas Pipeline

Transco - Premier System Serving the Atlantic Seaboard Peak day design capacity of 8.1 Bcf/d Assets 10,500 miles of pipeline 7 storage facilities 44 compressor stations; 1,630,000 HP Rate base $2.7 B Zonal rate structure Seasonal storage 220 Bcf of capacity 4,870 MMcf/d of withdrawal capability Gas Pipeline Zone 1 Zone 2 Zone 3 Zone 4 Zone 4A Zone 5 Zone 6

Rate Comparison * Transco vs Competition $- $0.25 $0.50 $0.75 $1.00 $1.25 $1.50 Transco SNG Transco SNG CGT Transco Iroquois CGT Tenn TETCO Demand Commodity Fuel Other Basis Zone 4 Zone 5 Zone 6 0.407 0.530 0.590 0.530 0.815 0.766 1.225 0.879 0.936 1.205 (Mississippi thru Georgia) (S Carolina thru Virginia) (Maryland thru New York) Transco - Rate Comparisons Gas Pipeline * 100% Load Factor

Northwest - Multiple Supply Sources Serving the Northwest Peak Day design capacity of 3.5 Bcf/d Assets 4,100 miles of pipeline 3 storage facilities 42 compressor stations; 350,000 HP Rate base $1.1 B Postage stamp rates Seasonal storage 12.4 Bcf of capacity 608 MMcf/d of withdrawal capability Gas Pipeline Northwest

Reno, NV Medford, OR Spokane, WA Rate Comparison * Northwest vs Competition 0.810 1.053 0.394 0.192 0.394 1.317 Northwest - Rate Comparisons Gas Pipeline * 100% Load Factor $- $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 Northwest / Piaute GTN / Tuscarora Northwest GTN Northwest GTN Demand Commodity Third Party Fuel Basis

Gulfstream - Pipeline To A Fast Growing Market Large supply sources Mobile Bay Eastern Louisiana Mississippi High growth Gas fired power generation Population Long term contracts Average contract life 20 years Assets Capacity 1.1 Bcfd 700 miles of pipeline; primarily 36" 1 compressor station; 114,000 HP 1 gas processing plant Rate base $1.4 B Gas Pipeline Gulfstream Phase I 591 miles of pipe 114,000 HP compression $1.461 B capital In service May 2002 Gulfstream Phase II 109 miles of pipe 350 Mdt/d lateral capacity $225 MM capital In service Feb 2005

Favorable Demand Outlook Gas Pipeline Gulfstream (50% Ownership) Underground storage LNG peaking facility Transco Northwest Source: EEA Apr 05 Compass Total Demand Increase: 9.99 Bcf/d Compound Annual Growth Rate: 2.3% 0.15 1.8% 1.05 2.6% 0.46 3.4% 1.35 3.1% 0.24 2.4% 1.11 7.0% 0.30 1.4% 0.81 0.9% 0.99 4.8% 0.61 4.3% 0.54 2.8% 0.48 0.8% Bcf/d CAGR 0.83 5.5% 2004 - 2010 US + Canada 1.03 1.8%

Gas Pipeline Gulfstream (50% Ownership) Underground storage LNG peaking facility Transco Northwest - -1.53 Arctic 1.06* - -0.05 1.66 - -0.5 - -0.16 - -0.05 - -0.64 - -1.04 2.00 - -.05 ..35 - -0.02 * Mackenzie pipeline on-stream in 09 2004 - 2010 US + Canada WCSB Net Increase in Production: 1.65 Bcf/d Source: EEA Apr 05 Compass ..02 Bcf/d Supply Outlook - Access to Diverse Supplies

Positioned for Proposed & Existing LNG Imports Gas Pipeline Net Increase (Bcfd) Production: 1.65 LNG + Other: 8.34 Total 9.99

Accommodating LNG Imports WGP Advantages Serves markets that are large, diverse, and growing Proximity to LNG terminals Existing Cove Point facility on the east coast Advancing Gulf Coast projects Pacific Northwest proposals Redelivery flexibility Low rates Challenges Maintaining gas quality Maintaining operational flexibility Gas Pipeline

Nature of Pipeline Investments Utility franchise (FERC regulation) Relatively capital intensive with long lived immobile facilities Stable and predictable cash flow that provides financial synergies and higher credit ratings Gas Pipeline

How Pipelines Make Money Provide transportation and storage service under firm and interruptible contracts Most revenue collected under long term contracts with credit- worthy customers Relatively limited exposure to throughput and basis fluctuations Subject to Cost of Service regulation Allowed to recover prudently incurred costs Rates include an allowed rate of return Gas Pipeline

Allowed to recover costs through rates based on "Cost of Service" Cost of Service O&M and A&G Expenses + Depreciation Expense + Taxes Other Than Income (state, ad valorem) + Federal and State Income Taxes + Allowed Return Cost of Service (revenue) Allowed Return = Rate Base x Rate of Return % Rate Base = Net Plant + Working Capital - Deferred Taxes Rate of Return % = weighted average cost of debt and equity How Pipelines Make Money - The Mechanics Gas Pipeline

How Pipelines Make Money - The Mechanics Gas Pipeline Straight Fixed Variable Rate Design Cost of Service Fixed Costs Variable Costs O&M and A&G Depreciation Taxes other than income Fed. & State income taxes Allowed return O&M Compressor Station Operating Expenses Maintenance Expenses Non-Tracked Fuel Costs* Reservation Commodity Rates * Primarily non-compression related electric power costs

How Pipelines Make Money - The Mechanics FERC must approve rates through a rate case Customers and other interested parties may intervene Extensive documentation and support is presented in the rate case filing and through the discovery process Issues raised during the rate case are resolved either through litigation or a mutually agreeable settlement Key components include: Capital Investment O&M and Other Expenses Rate of Return % Anticipated Volumes Rate case timeline Filing Date - 6 months prior to effective date (30 day notice + 5 month suspension) Test Period - 9 months preceding the effective date Base Period - 12 months ending no more than 120 days prior to the filing date Gas Pipeline

Future Rate Case - Northwest Next anticipated rate case effective Q1 2007 26-inch Replacement Project the primary driver Last rate case effective March 1997 No requirement to file Gas Pipeline J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D <-> NWPL Docket No. RP06-XX Key Dates New Rates in Effect -----------------------------------> <--------------- Test Period ---------------> 2007 5 Month <--- Suspension ---> Period 2005 2006 <------------------------- Base Period -------------------------> 30 Day Notice Period 8/1/06 Requested Effective Date 1/1/07 Expected Effective Date 7/1/2006 Anticipated Filing Date

Future Rate Case - Transco Gas Pipeline Next rate case effective Q1 2007 Driven by Clean Air Act and Pipeline Safety Improvement Act spending Last rate case effective September 2001 Required to file per last settlement J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D 5 Month <-> <--- Suspension ---> Period TGPL Docket No. RP06-XX Key Dates 2007 New Rates in Effect -----------------------------------> 2005 2006 <-------------------------- Base Period -----------------------------> <-----------------Test Period-----------------> 30 Day Notice Period 10/1/06 Requested Effective Date 3/1/07 Expected Effective Date 9/1/2006 Anticipated Filing Date

Approximately 90% of 2004 operating revenues were from transportation and storage reservation charges 2004 Revenue Revenue Breakout Gas Pipeline Transportation Reservation includes incrementally priced projects Deals Transportation Demand 0.903 Storage Demand 0.024 Transportation Commodity 0.061 Storage Commodity 0.007 Other 0.005 Deals Transportation Demand 0.81 Storage Demand 0.068 Transportation Commodity 0.104 Storage Commodity 0.005 Other 0.013 NWPL 93% TGPL 88% Transportation Reservation Storage Reservation Transportation Commodity Storage Commodity Other

Top Customers - Large, Long Term, Credit Worthy TGPL Customer Credit Rating PSEG BBB KeySpan A+ AGL Resources A- Piedmont A Con Ed A SCANA A- Exelon A- NWPL Customer Credit Rating Puget Sound BBB- N W Natural A+ Avista Corp BB+ Cascade Natural Gas BBB+ Pan Alberta Gas guarantee Intermountain Gas private Occidental Energy Marketing guarantee Gas Pipeline

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) 1Q05 Earnings Call

Cornerstone of the Williams Portfolio Stable and predictable cash flow Future investment opportunities Strong and diverse markets with growth Strong and diverse supply Premier pipeline franchises Both Transco and Northwest received top ranking in the Mastio & Co. customer survey Transco ranked #1 in the Northeast Region in customer satisfaction among 16 mega pipelines Northwest ranked #1 in Western Region in customer satisfaction for the second year in a row Gas Pipeline

Q&A Questions? Gas Pipeline

Exploration & Production Update Ralph Hill, Senior Vice President Exploration & Production May 12, 2005

Grow our premier position in select regions, utilizing our expertise in basin-centered tight sands/shale and coal bed methane (CBM) Strategy remains rapid development of our significant drilling inventory Maintain top quartile position in efficiency and cost measures Be the operator of choice for landowners or producers seeking partners Leverage technological advancements in drilling, completion and operational activities Expand core areas through bolt-on acquisitions and farm-ins Add new core growth areas through strategic acquisitions Strategy Exploration & Production

1Q 2005 Segment Profit over 100% higher than 1Q04 1Q 2005 production up 22%, 112 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 2005 Accomplishments Exploration & Production Recurring Segment Profit + Depreciation 0 20 40 60 80 100 120 140 160 1Q 2Q 3Q 4Q 2004 2005

North American unconventional natural gas production Focused portfolio of large well-defined resources Repeatability of results, very high success rate Long-term, low-risk, high-return drilling portfolio Strong organic production growth R/P ratio of 15.6 years Drilling approx. 1,400 wells/yr Powder River Piceance San Juan Arkoma Unique Drilling Portfolio Exploration & Production

Proved, Probable & Possible Reserves 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, and Caney Shale. 2004 Year End Proved Reserves Domestic Reserves Exploration & Production Piceance 62% Powder River 10% San Juan 22% Mid-Cont. & Other 6% Powder River 30% Piceance 53% San Juan 14% Mid-Cont. & Other 3%

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 Domestic Reserves Exploration & Production Transfers of Probable to Proved (Bcf) 2002 2003 2004 Total Total for retained basins 313 408 451 1,172

0 100 200 300 400 500 600 700 800 900 1000 2004 2005* 2006* 2007* MMcfd Total Net Production * Assumes Midpoint of Guidance CAGR 16% Production Growth Exploration & Production

Cash Margin Analysis Exploration & Production Reflective of core basins * Includes LOE, G&A, taxes and gathering ** Includes acquisition and development expenditures / proved reserves ('02-'04 average) 3-Year Average (2005-07) Cash Margin Cash Costs* $4.56 $1.56 $0.78 $3.00 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs**

Basin Summaries Exploration & Production

Proved reserves total 37 MMboe (222 Bcfe) 5,700 Bbl/d net oil & liquids production 17 MMcf/d net gas production 69% ownership in Apco Argentina 10% ownership in La Concepcion In-fill, field extension drilling Exploration upside High investment returns, fast cash cycle Complements domestic long life reserves strategy Provides perspective on international opportunities 3.0% Acambuco 50% Capricorn Exploration Permit 23% direct interest in Entre Lomas. 40.8% stock interest in Petrolera 82% Canadon Ramirez 25.8% interest in three Tierra del Fuego concessions International E&P Exploration & Production

CBM and emerging shale activity Williams' Basin Statistics: Proved reserves total 121Bcfe ~20 MMcf/d net production growing 10-15% annually Leasehold approx. 118,000 net acres ~325 total wells, 70% operated Have drilled 162 extended reach horizontal lateral wells 2004 drilling success rate of 90% 50 - 60 Operated wells drilled per year Caney and Woodford Shale potential offers growth opportunities Caney Shale Exposure ~68,000 net acres Drilling 3rd operated well Gas saturated column offers conventional upside Application of horizontal technology Arkoma Basin - Horizontal Expertise Exploration & Production

Conventional and coal bed methane production Long life / slow decline wells Williams' proved reserves total 671 Bcfe ~150 MMcfe/d of net production growing 3-5% annually next two years 13% growth year over year Low risk in-fill drilling 40-60 operated wells drilled per year 200 - 250 undeveloped locations Attractive returns with near 100% success rates Leasehold 121,200 net acres ~680 operated and 1,900+ joint interest wells Good pipeline infrastructure/market access San Juan Basin - Foundation Exploration & Production

Current CBM production 891 MMcfe/d* 39 Tcf Gas-In-Place** 18,400 wells drilled to date* 33,600 additional potential locations in WY 15,000 potential locations in MT First significant CBM production 1995 * WOGCC Data January 2005 ** USGS Estimate 2002 Powder River Basin Overview Exploration & Production

High potential, low-risk development play, low cost wells Williams' proved reserves total 299 Bcfe Leasehold 1,021,400 gross/466,000 net acres ~4,810 total wells, 53% operated 2004 drilling success rate of 99% ~110 MMcfe/d net production ~9,000 drilling locations; 46% operated Powder River Basin - Ready to Roll Again Exploration & Production

Powder River Basin Big George & Wyodak Coal Fairways Williams Big George Gross Production Increasing 97 MMcfd 100 Miles 60 Miles Wyodak Fairway 685.3 MMcfd* CAMPBELL COUNTY Gillette JOHNSON SHERIDAN Big George Fairway 205.2 MMcfd Williams Operated Pilots Scale 0 6 miles Partner Operated Pilots Other Industry Pilots Carr Draw South Prong Schoonover Road S.G. Palo Pleasantville Areas Kingsbury Area All Night Creek Area Bullwhacker Creek WOGCC Data Jan 2005 ** April 2005 Exploration & Production

Powder River Basin Williams Operated Big George Daily Production Exploration & Production CAGR 107% 0 10 20 30 40 50 60 70 80 90 100 Apr-01 Jun-01 Aug-01 Oct-01 Dec-01 Feb-02 Apr-02 Jun-02 Aug-02 Oct-02 Dec-02 Feb-03 Apr-03 Jun-03 Aug-03 Oct-03 Dec-03 Feb-04 Apr-04 Jun-04 Aug-04 Oct-04 Dec-04 Feb-05 Apr-05 MMCFD - Gross

Powder River Basin Net Production Forecast Exploration & Production 136 - 151 111 - 123 100 - 111 118 MMcfe/d 770 - 775 770 - 775 700 - 775 705 Wells Spud CAGR 12% 43 36 - 40 41 - 45 45 - 50 0 20 40 60 80 100 2004 2005F 2006F 2007F Bcfe

Piceance Basin - Cornerstone Asset Exploration & Production

Piceance Basin Record of Results Delivery Annual Net Production Reserves CAGR 11% Exploration & Production 1,310 1,370 1,560 1,806 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2001 2002 2003 2004 Bcfe 45 60 62 81 0 50 100 2001 2002 2003 2004 Bcfe Wells Spud 109 124 76 243 MMcfe/d 123 164 170 222 CAGR 21%

Production ~900 MMcfe/d ~1,400,000 acres Gas-in-place estimates over 100 Tcf ~2,000 Mesaverde active wells ~3,000 additional locations on Williams valley acreage alone Piceance Basin Overview Exploration & Production

Piceance Basin Area Map 20th Year of Development 134,000 Net Acres One of the largest natural gas producers in Piceance Basin >350 MMcfd Gross Operated Production Operate 1100+ wells, 98% WI Operate 250+ miles of gathering and 4 gas plants Access to 5 major interstate / intrastate pipelines Currently 13 drilling rigs operating Exploration & Production

Piceance Basin Gas Recovery Estimates vs. Well Density Typical Piceance Valley Section 100 Bcf Gas in Place / Square Mile 20-Acre Development 32 Wells / Section Remaining Gas in Place 55 Bcf 45 Bcf, 45% GIP 1.4 Bcf per well 1.4 Bcf per well 40-Acre Development 16 Wells / Section 22 Bcf, 22% GIP Remaining Gas in Place 78 Bcf 1.4 Bcf per well 1.4 Bcf per well 10-Acre Development 64 Wells / Section Total Recoverable Gas 90 Bcf, 90% GIP 1.4 Bcf per well 1.4 Bcf per well Exploration & Production

Piceance Basin 2005 Approved 10-Acre Applications Exploration & Production

Piceance Basin Record of Capital and EUR Average 1.41 Average $1,034 * Gross Estimated Ultimate Recovery Exploration & Production Average EUR* (BCF) 1.47 1.41 1.42 1.46 1.5 1.36 1.25 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 1998 1999 2000 2001 2002 2003 2004 Gross EUR (BCF) Average Cost (M$) 1,061 1,045 1,017 1,111 943 890 904 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 1998 1999 2000 2001 2002 2003 2004

Piceance Basin Drilling Efficiency * Days from spud to rig release. Does not include rig move time. Exploration & Production 0 5 10 15 20 25 30 35 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Purpose Build Rig Program Incremental Activity ~50 ~20 0 Production MMCFD ~50 ~30 0 Segment Profit $MM ~200 ~200 ~30 Capital $MM * 8 6 0 Rigs 150 125 3 Operated Spuds 2007 2006 2005 Piceance Rig Design Improved performance in Piceance Basin drilling conditions Reduce the number and size of surface locations H&P Deal Total 10 rigs 3 year commitment First delivery November 2005 1 * Capital of $30 million in '05 and $115 million in '06 are for Facilities Exploration & Production

CIG Questar TransColo NWPL WIC Expansion CIG/NWPL/Williams Greasewood DeBeque Lateral Gathering & Processing: Currently 600 MMcf/d Greasewood line DeBeque Lateral Rifle interconnect CIG interconnect Transport: TransColorado to San Juan TransColorado to Greasewood WIC expansion CIG NWPL Piceance Basin Pipeline Infrastructure Capacity Exploration & Production

Piceance Basin Positioned for Continuing Valley Growth Wells Spud 243 260 - 280 400 - 450 450 - 500 Net MMcfe/d 222 282 - 313 359 - 401 427 - 475 Exploration & Production Net Production 156 - 173 131 - 146 103 - 114 81 0 50 100 150 200 2004 2005F 2006F 2007F Bcfe CAGR 27%

Williams Wells Industry Wells Earn 28,383 gross / 14,475 net acres Drilling obligations - 6 wells in 2 years; 3 Drilled, 3 remaining Williams operated at 51% WI 87% average NRI ~770 potential gross well locations ~700 net Bcf potential reserves Contiguous acreage block Additional Piceance Basin Opportunities Ryan Gulch Project Area Exploration & Production

17,316 gross/14,545 net acres Drilling obligation - 4 wells/year for 6 years 84% average NRI Williams operated at 100% WI ~500 potential well locations ~500 BCF potential reserves Contiguous acreage block 6 miles West of Grand Valley where completions average 1.2 Bcf/well Produces into Williams' Grand Valley Gathering System Additional Piceance Basin Opportunities Trail Ridge Project Area Exploration & Production Williams Wells Industry Wells

1,908 gross and net acres 85% average NRI 189 potential well locations ~200 Bcf potential reserves, at 1.3 BCF/well Adjacent well, which has a 1.3 Bcf Estimated Ultimate Recovery (EUR) Produces into Williams' Grand Valley Gathering System Additional Piceance Basin Opportunities Red Point Project Area Exploration & Production Williams Wells Industry Wells

Additional Piceance Basin Opportunities Summary Prospect Net Acres Gross Potential Locations* Net Potential Reserves*(BCF) Ryan Gulch (40 acre spacing) 14,475 770 700 Trail Ridge (40 acre spacing) 14,545 500 500 Red Point (10 acre spacing) 1,908 189 200 Total 30,928 1,459 1,400 * Not included in US Reserves summary of 2.7 Tcf proved and ~7 Tcf proved, probable and possible. 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 - 1075 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) 284 298 172 Price (Mcfe) $4.46 $4.39 $4.18 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 2005-2007 Guidance Exploration & Production 1Q05 Earnings Call

Delivering meaningful volume growth through expanded 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 Exciting new opportunities Trail Ridge, Ryan Gulch, Red Point, and Caney Shale Strategy remains rapid development of our premier drilling inventory Key Points Exploration & Production

Q&A Questions? Exploration & Production

Appendix Appendix May 12, 2005

Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Note: Est. NG Portfolio Cash Flows represent expected cashflows from NG Storage, Transport and hedges. Estimated Total Cash Flows Undiscounted dollars in millions Combined Power Portfolio Estimated as of 3/31/05 Q1A 2005A+F 2006F 2007F 2008-2010F 2011-2022F Tolling Demand Payment Obligations ($89) ($368) ($402) ($406) ($1,233) ($3,868) Resale of Tolling $41 $126 $106 $96 $158 $0 Full Requirements ($2) $3 ($7) $0 $6 $26 Long-term Physical Forward Power Sales $22 $25 ($13) ($1) $29 $0 OTC Hedges $34 $146 $205 $66 $107 $58 Estimated Hedged Tolling Revenues $15 $184 $279 $283 $588 $279 Subtotal $21 $116 $168 $38 ($345) ($3,505) Estimated Merchant Cash Flows $0 $79 $28 $156 $873 $5,850 Est. Combined Power Portfolio Cash Flows $21 $195 $196 $194 $528 $2,345 Est. NG Portfolio Cash Flows $11 ($14) $1 $5 $70 ($63) SG&A and Other ($26) ($81) ($73) ($75) ($225) ($800) Subtotal $6 $100 $124 $124 $373 $1,482 Working Capital and Other $42 $23 $1 $3 $6 $103 Estimated Cash Flows After SG&A $48 $123 $125 $127 $379 $1,585 Capacity Available (in MW) 5,149 7,723 7,723 7,723 7,723 Expected Output (in MW) 1,533 2,289 2,530 2,917 3,479 Total Volume Hedged (in MW) 1,451 1,977 1,867 1,172 136 Percentage Volume Hedges 95% 91% 73% 40% 5% Appendix: Power

West - Estimated Total Cash Flows 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: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. West Power Portfolio Estimated as of 3/31/05 Q1A 2005A+F 2006F 2007F 2008-2010F 2011-2018F Tolling Demand Payment Obligations ($38) ($141) ($156) ($157) ($482) ($1,243) Resale of Tolling $41 $126 $106 $96 $158 $0 Long-term Physical Forward Power Sales $22 $22 ($13) ($1) $29 $0 OTC Hedges $27 $101 $145 $44 $52 ($4) Est. Tolling Cash Flows Associated With Hedge $4 $141 $191 $201 $396 $16 Subtotal $56 $249 $273 $183 $153 ($1,231) Estimated Merchant Cash Flows $0 $48 $10 $70 $439 $2,607 Estimated Cash Flows $56 $297 $283 $253 $592 $1,376 Capacity Available (in MW) 2,761 4,141 4,141 4,141 4,141 Expected Output (in MW) 938 1,314 1,383 1,556 1,790 Total Volume Hedged (in MW) 927 1,170 1,196 738 12 Percentage Volume Hedges 99% 89% 87% 47% 1% Appendix: Power

Central - Estimated Total Cash Flows 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: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Appendix: Power

East - Estimated Total Cash Flows 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: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Appendix: Power

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 1Q05 Earnings Call Appendix: Power

Segment Profit to Cash Flow 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 1Q05 Earnings Call Appendix: Power

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. 1Q05 Earnings Call Combined Power Portfolio Actual 1Q05 v. Forecast 1Q05 1Q05 A 1Q05 F Tolling Demand Payment Obligations ($89) ($84) Resale of Tolling 41 40 Full Requirements (2) (1) Long-term Physical Forward Power Sales 22 21 OTC Hedges 34 33 Estimated Merchant Cash Flows 15 10 Total Cash Flows $21 $19 Working Capital & Other 53 76 SG&A and Other (26) (17) Estimated Cash Flows After SG&A $48 $78 Appendix: 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 1Q05 Earnings Call Appendix: Power

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 Appendix: Power

WMB 1 E&P 2 Midstream 3 Power 4 Natural Gas Natural Gas Processing Margin West Spark Spread (Per MMBTU) (Per MMBTU) (Per Gallon) (Per MWh) Price Increase $0.10 $0.10 $0.01 $5.00 2005 ($3) - $0 $5 - $6 $7 - $12 $5 - $10 2006 ($2) - $1 $10 - $11 $10 - $15 $5 - $15 2007 $8 - $11 $16 - $17 $10 - $15 $5 - $15 1 Assumes a correlated movement in prices across all commodities, including spreads, for all Williams business units. 2 Assumes a price increase on E&P position only (production and hedges). 3 Assumes a non-correlated change in NGL processing spread (i.e. change in NGL price only). 4 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Enterprise Risk Management Sensitivity Scenarios in millions Appendix: Power