Williams Power Tutorial November 18, 2004 Exhibit 99.2

Forward Looking Statements Williams' 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" with in the meaning of 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: changes in general economic conditions and changes in the industries in which Williams conducts business; changes in federal or state laws and regulations to which Williams is subject, including tax, environmental and employment laws and regulations; the cost and outcomes of legal and administrative claims proceedings, investigations, or inquiries; the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions; the level of creditworthiness of counterparties to our transactions; the amount of collateral required to be posted from time to time in our transactions; the effect of changes in accounting policies; the ability to control costs; the ability of each business unit to successfully implement key systems, such as order entry systems and service delivery systems; the impact of future federal and state regulations of business activities, including allowed rates of return, the pace of deregulation in retail natural gas and electricity markets, and the resolution of other regulatory matters; changes in environmental and other laws and regulations to which Williams and its subsidiaries are subject or other external factors over which we have no control; changes in foreign economies, currencies, laws and regulations, and political climates, especially in Canada, Argentina, Brazil, and Venezuela, where Williams has direct investments; the timing and extent of changes in commodity prices, interest rates, and foreign currency exchange rates; the weather and other natural phenomena; the ability of Williams to develop or access expanded markets and product offerings as well as their ability to maintain existing markets; the ability of Williams and its subsidiaries to obtain governmental and regulatory approval of various expansion projects; future utilization of pipeline capacity, which can depend on energy prices, competition from other pipelines and alternative fuels, the general level of natural gas and petroleum product demand, decisions by customers not to renew expiring natural gas transportation contracts; the accuracy of estimated hydrocarbon reserves and seismic data; and global and domestic economic repercussions from terrorist activities and the government's response to such terrorist activities. 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.

The Road Ahead 2004 2005 2006 2007 & beyond Risk Reduction Spark spreads improve Continue to reduce risk, generate cash, meet contractual commitments 3Q '04 Earnings Call

Key Points Portfolio continues to generate positive cash flows Market conditions continue to slowly rebound Improving market liquidity Spark spreads are stabilizing Favorable political messages from California and FERC Cash management continues to improve New risk-reducing contracts Favorable California PUC decision Adoption of hedge accounting Lowers earnings volatility Residual MTM impact lowers future reported earnings Segment profit after MTM adjustments unchanged No effect on cash flow guidance 3Q '04 Earnings Call

Today's Agenda Business overview Accounting discussion Terms History Revenue recognition standards Financial measures Examples Updated financials Q&A

Business Overview

Physical Natural Gas Average annual requirements 2.8 Bcf/d with peak of 3.5 Bcf/d 40% for Power 20% power-plant supply 20% third-party transactions 60% for Williams' core businesses Transportation 2.5 Bcf/d 30% for gas marketing (including power-generation fuel) 70% for Williams' core businesses Storage 17 Bcf 67% for gas marketing (including power-generation fuel) 33% for Williams' core businesses Improving market liquidity and credit

Power Portfolio Owned: Milagro 60 MW Natural-gas fired Tolling: AES 4000 4,141 MW Forward Power Sale: CDWR A, B, C 50-700 MW max Resale of Toll: CDWR D 1,045-1,175 MW Tolling: Cleco Evangeline 765 MW Forward Power Sale: Cleco Evangeline 100-250 MW Tolling: Kinder Morgan - Jackson 541 MW Full Requirements: Allegheny Electric Co-op 515-600 MW Tolling: AES Ironwood 666 MW Tolling: AES Red Oak 766 MW Owned: Hazleton 147 MW Natural gas-fired Full Requirements: Four Georgia EMCs 600-1,500 MW Tolling: Tenaska Lindsay Hill 844 MW West Mid-Continent East

Portfolio Characteristics Asset-based power business with long-term contractual commitments 6 tolling contracts and 2 owned facilities Approximately 7,900 megawatts Approximately $400 million in annual demand charges 8 key offsetting contracts Over-the-counter (OTC) hedges Current estimated demand payment coverage is 98% through 2010* * See appendix for detailed estimate as of 9/30/04

Regional Discussions

Key Messages West Pro-competitive environment Demonstrated political support of stable, competitive markets CPUC vote to accelerate by 2 years reserve margin requirements of 15 percent CPUC order for utilities to secure capacity to ensure reliability instead of relying on CaISO Potential for financial upside Record peak loads indicative of economic recovery Locational marginal pricing implementation in early 2007 adds value to in-city generation capacity; not reflected in cash flow forecasts Aging units in strategic load pockets Price caps on generation and capacity could limit value, hinder supply growth, narrow spark spreads in short term

Key Messages Mid-Continent Favorable market developments, but no significant impact on portfolio value expected Kinder Morgan Jackson Midwest ISO expected to begin locational marginal pricing (LMP)- based market in 1Q05 Capacity and ancillary markets likely in 2006 Grid redesign allows access to new, more liquid markets Depressed spark spreads expected for several years Cleco Evangeline Southwest Power Pool (SPP) regional transmission organization recognized Oct. 4 Increasing pressure on utilities to support competition Participating in requests for proposal

Key Messages East Pennsylvania-New Jersey-Maryland (PJM) footprint continues to expand, increasing market size, efficiency and liquidity Market redesign will improve capacity prices and recognize locational value of capacity Filing expected mid-2005 Potential significant impact to portfolio value; not reflected in cash flow forecasts Transmission-related issues adding value to Red Oak

FAQs What is your view of re-regulation? Re-regulation really means utilities build/acquire generation RTOs, market-based rates and wholesale competition are here to stay Existing capacity with current locational advantages may not be replaced by new generation Formal competitive solicitation rules are improving

FAQs What about the imputed debt for purchased power agreements? S&P formula imputes debt in 'buy' scenario; burdens 'build' scenarios with debt as projects are financed Other 'build' risk factors and costs must be considered Properly structured requests for offer (RFOs) will include build and buy risks/costs Objective evaluation of bids is vital for consumers Formal competitive solicitation rules are improving

FAQs How will higher gas prices impact your power portfolio? Current hedges reduce impact Generally power and gas prices have moved in tandem, minimizing the impact to the portfolio Williams manages natural gas risk at the enterprise level

Accounting Discussion

Power Portfolio History* SFAS 133 - adopt hedge accounting** SFAS 133 - derivatives still marked-to- market, but not eligible for hedge accounting due to stated intent to exit business EITF 02-3 - non-derivatives (tolling, full requirements, etc.) changed to accrual accounting SFAS 133 - derivatives marked-to-market EITFs 98-10 and 00-17 - all other energy-trading contracts marked-to-market Pre-2003 2003 Q404 * Excludes E&P hedges ** Exceptions include interest rate hedges, non-qualifying hedges and certain other positions.

Pre-Hedge Accounting Power did not previously qualify for cash flow hedge accounting because of stated intent to exit Derivative instruments accounted for on a fair value (MTM) basis Changes in the forward value of these instruments are recorded as unrealized gains / losses on the income statement and balance sheet Non-derivatives reported on an accrual basis Result is that GAAP earnings were volatile, one-sided, and did not track cash flows or economic results

Adoption of Hedge Accounting Hedge accounting has no impact on cash flows or economic value Application of hedge accounting will significantly reduce Power's mark-to-market (MTM) earnings volatility But MTM earnings will not be eliminated Economic hedges that do not qualify for SFAS 133 hedge accounting Speculative positions Residual MTM lowers future guidance

Hedge Accounting Example Event 1 on Dec. 1, 2003: Tolling agreement in place; no fixed-price hedge Forecast of Jan05 Sale Est. Tutorial Cash Flows Financial Statement Recognition Var. Cost of Gen. Market Price Fixed- Price Hedge Tolling CF Assoc. w/Hedges OTC Hedges Net Accr. Rev. Unreal Gain/ (Loss) Realized Hedge Rev. OCI Gain/ (Loss) Deriv. Asset CFFO Dec03 15 40 - 25 - - 25 - - - - - - Income Statement Bal. Sheet Cash Flow Stmt. Merch. Cash Flows

Hedge Accounting Example Event 2 on Jan. 1, 2004: Enter into fixed-price derivative to hedge power Est. Tutorial Cash Flows Financial Statement Recognition Dec03 15 40 - 25 - - 25 - - - - - - Jan04 15 40 40 - 25 - 25 - 0 - - 0 - Income Statement Bal. Sheet Cash Flow Stmt. Var. Cost of Gen. Market Price Fixed- Price Hedge Tolling CF Assoc. w/Hedges OTC Hedges Accr. Rev. Unreal Gain/ (Loss) Realized Hedge Rev. OCI Gain/ (Loss) Deriv. Asset CFFO Merch. Cash Flows Forecast of Jan05 Sale Net

Hedge Accounting Example Event 3 on Sept. 30, 2004: Report market movement since date of hedge Est. Tutorial Cash Flows Financial Statement Recognition Dec03 15 40 - 25 - - 25 - - - - - - Jan04 15 40 40 - 25 - 25 - 0 - - 0 - Sep04 15 30 40 - 15 10 25 - 10 - - 10 - Income Statement Bal. Sheet Cash Flow Stmt. Var. Cost of Gen. Market Price Fixed- Price Hedge Tolling CF Assoc. w/Hedges OTC Hedges Accr. Rev. Unreal Gain/ (Loss) Realized Hedge Rev. OCI Gain/ (Loss) Deriv. Asset CFFO Merch. Cash Flows Forecast of Jan05 Sale Net

Hedge Accounting Example Event 4 on Dec. 31, 2004: Adoption of hedge accounting on Oct. 1 reported in year-end results Est. Tutorial Cash Flows Financial Statement Recognition Dec03 15 40 - 25 - - 25 - - - - - - Jan04 15 40 40 - 25 - 25 - 0 - - 0 - Sep04 15 30 40 - 15 10 25 - 10 - - 10 - Dec04 15 22 40 - 7 18 25 - - - 8 18 - Income Statement Bal. Sheet Cash Flow Stmt. Var. Cost of Gen. Market Price Fixed- Price Hedge Tolling CF Assoc. w/Hedges OTC Hedges Accr. Rev. Unreal Gain/ (Loss) Realized Hedge Rev. OCI Gain/ (Loss) Deriv. Asset CFFO Merch. Cash Flows Forecast of Jan05 Sale Net

Hedge Accounting Example Event 5 on Jan. 31, 2005: Settle and realize the hedge and the forecasted sale of power Est. Tutorial Cash Flows Financial Statement Recognition Dec03 15 40 - 25 - - 25 - - - - - - Jan04 15 40 40 - 25 - 25 - 0 - - 0 - Sep04 15 30 40 - 15 10 25 - 10 - - 10 - Dec04 15 22 40 - 7 18 25 - - - 8 18 - Income Statement Bal. Sheet Cash Flow Stmt. Jan05 15 22 40 - 7 18 25 7 - 8 - - 25 Var. Cost of Gen. Market Price Fixed- Price Hedge Tolling CF Assoc. w/Hedges OTC Hedges Accr. Rev. Unreal Gain/ (Loss) Realized Hedge Rev. OCI Gain/ (Loss) Deriv. Asset CFFO Merch. Cash Flows Forecast of Jan05 Sale Net

Hedge Accounting Example Events 1 through 5: Summary Est. Tutorial Cash Flows Financial Statement Recognition Dec03 15 40 - 25 - - 25 - - - - - - Jan04 15 40 40 - 25 - 25 - 0 - - 0 - Sep04 15 30 40 - 15 10 25 - 10 - - 10 - Dec04 15 22 40 - 7 18 25 - - - 8 18 - Income Statement Bal. Sheet Cash Flow Stmt. Jan05 15 22 40 - 7 18 25 7 - 8 - - 25 Var. Cost of Gen. Market Price Fixed- Price Hedge Tolling CF Assoc. w/Hedges OTC Hedges Accr. Rev. Unreal Gain/ (Loss) Realized Hedge Rev. OCI Gain/ (Loss) Deriv. Asset CFFO Merch. Cash Flows Forecast of Jan05 Sale Net

Key Takeaways from Example Cash flows unaffected Residual MTM impact lowers future reported earnings Disconnect between cash flows and income statement Example: 2005 segment profit guidance of ($200) million to ($100) million; cash flow from operations of $50 million to $150 million

Revenue Recognition Today Summary of Accounting Treatment by Contract Type Contract Type Acctg Acctg Income Revenues "Bucket" Method =Cash? Gross/Net Tolling Non-Derivative Accrual Yes Gross Full Requirements Non-Derivative Accrual Yes Gross Storage Non-Derivative Accrual Yes Gross Transportation Non-Derivative Accrual Yes Gross Transmission Non-Derivative Accrual Yes Gross Firm Service Non-Derivative Accrual Yes Gross CDWR Product D Non-Derivative Accrual Yes Gross Spot Physical Trxs Non-Derivative Accrual Yes Gross CDWR ABC Derivative Normal P&S No Gross & Net OTC/NYMEX Fins Derivative MTM/Hedge No/Yes* Gross & Net Forward Physicals Derivative MTM/Hedge No/Yes* Gross & Net * Due to existing day-1 value of hedges on date of adoption date of hedge accounting, income will not equal cash. Over time, however, as new hedges are put on with day-1 fair value of zero, hedge accounting treatment will result in income = cash.

Financial Discussion

Financial Measures Segment profit Segment profit after MTM adjustments Cash flows from operations Portfolio cash flows

3rd Quarter YTD 2004 2003 2004 2003 Segment Profit Dollars in millions Gross Margin $131 $60 $202 $198 SG&A (20) (26) (56) (107) Op. Exp. & Other Inc / (Exp) (3) 4 (25) 150 Equity Earnings (Losses) 1 (1) 0 (5) Segment Profit $109 $37 $121 $236 Includes: Aux Sable Impairment - 6 - 14 Regulatory Settlement - - - 20 Prior period correction* - (1) - (108) Gains on sale of assets/contracts - (27) - (208) Reduction in force costs - - - 12 Recurring Segment Profit $109 $15 $121 ($34) * 2003 amounts reflect corrections as disclosed in 2003 10-K 3Q '04 Earnings Call

Segment Profit After MTM Adjustments What does this measure mean and why do we use it? Reflects financial results as if Power had never recorded any prior mark-to-market earnings; that is, if Power had always used accrual-based accounting for its portfolio Because hedges had value on date of hedge designation, this will result in difference between economic and reported results until hedges roll off Does not include working capital changes as does CFFO Approximates forecasted future portfolio cash flows Non-GAAP measure Note: See example in appendix.

Dollars in millions 1Schedule of expected realization of MTM gains/losses previously recognized is included in the Appendix. 3Q '04 Earnings Call Segment Profit After MTM Adjustments Forecast

Segment Profit to Cash Flow Dollars in millions 3Q '04 Earnings Call

Undiscounted Cash Flows Combined Segment Portfolio

1Some positions within these portfolios will be part of on-going business operations going forward. Undiscounted Cash Flows Residual (Legacy) Portfolio

2004 2005 2006 Previous Segment Profit Guidance $0 - $150 $50 - $150 $50 - $200 Current Forecast: Segment Profit after MTM Adjustment (20) 100 154 MTM Adjustments 67 (254) (269) Segment Profit $47 ($154) ($115) Revised Segment Profit Guidance $0 - $100 ($200) - ($100) ($200) - ($50) Cash Flow from Operations $150 - $350 $50 - $150 $50 - $200 Capital Expenditures $0 $0 $0 Dollars in millions 2004-2006 Guidance 3Q '04 Earnings Call

Summary

Summary Portfolio continues to generate positive cash flows Market conditions continue to slowly rebound Cash management continues to improve New risk-reducing contracts Favorable California PUC decision Adoption of hedge accounting Lowers earnings volatility Residual MTM impact lowers future reported earnings Segment profit after MTM adjustments unchanged No effect on cash flow guidance

Q&A

Appendix

Business Background

Tolling Concept Input Output Heat Rate (Fuel Conversion Efficiency) Natural Gas, Coal, Fuel Oil, Steam Power Power Generation (Fuel Converter) Tolling - Fuel conversion arrangement. Williams supplies fuel to plants and markets electricity output. Plant owner receives fixed fee and retains operational responsibility.

Heat Rate Concept Heat rate - The amount of fuel a power plant requires to produce one unit of power. A measure of the efficiency of generating plants. MMBtu MWh Key concepts The lower the heat rate, the more efficient the power-generation unit. Heat rate, when considered in conjunction with a unit's input fuel, generally determines a power-generation unit's economic viability in a given market. = Heat Rate

Power Cost: Power Price Fuel Cost Heat Rate Spark Spread Example: $42/Mwh $4/MMBtu 10MMBtu/MWh $2/MWh Spark Spread Concept Spark spread - The difference between the price of power and the cost it takes to produce it at a given facility. Key concepts The higher the spark spread, the higher the margin. A negative spark spread indicates it is more economical to purchase power to meet commitments than run generating facilities "out of the money." - x = - x = * Variable O&M costs typically included in spark-spread calculation, but not reflected here for sake of simplicity.

Types of Hedging Transactions Resale of Tolling Rights Resale of all or part of rights under tolling arrangements Example California Department of Water Resources (CDWR) Product D Essentially mirrors underlying tolling contract

Counterparty-tailored arrangement where Williams ... Serves counterparty's power demand requirements Dispatches counterparty's power plants / resources Markets excess energy produced by these resources and covers short positions Examples Georgia Electric Membership Corporations Four individual contracts Allegheny Electric Cooperative Types of Hedging Transactions Full Requirements

Physical or financial sale of a defined quantity of power over a set period of time Examples CDWR Products A, B and C Cleco Utility Group Standard OTC transactions Typical counterparties Power marketers Financial institutions Utilities Time horizon for hedging with forward contracts has lengthened as credit and liquidity have improved Types of Hedging Transactions Forward Power Sales

Non-standardized, near-term transactions Customized to meet customer/counterparty needs Term less than 3 years Examples Resale of tolling, full requirements, load serving, capacity Typical counterparties Utilities, municipalities and cooperatives Power marketers and retail aggregators Financial institutions Opportunity to hedge near-term volumes over next 2 to 3 years Types of Hedging Transactions Mid-Market Structured Sales

NERC Regions Red Oak Ironwood Hazelton Tenaska Evangeline AES 4000 KM Jackson

West

AES 4000 Tolling Arrangement 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 $2.28/MWh in 2004 Annual escalator is lesser of 2.5% or CPI 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

AES 4000 Capacities and Heat Rates Alamitos Unit 1 184 10.7 Unit 2 184 10.6 Unit 3 336 9.5 Unit 4 336 9.7 Unit 5 * 504 9.4 Unit 6 * 504 9.5 Unit 7 ** 133 16.5 Huntington Beach Unit 1 * 226 9.8 Unit 2 226 9.8 Unit 5 ** 133 16.5 Redondo Beach Unit 5 184 11.8 Unit 6 184 11.8 Unit 7 504 9.4 Unit 8 504 9.4 AES 4000 Total 4,141 9.84*** Capacity (MW) Heat Rate (MMBtu/MWh) * CDWR Product D; ** Unavailable due to environmental limitations; *** Excludes unavailable units Note: Based on AES 4000 tolling agreement.

AES 4000 Offsetting Contracts CDWR Products A, B, C Forward power sale Product A 200 MW - July 1, 2003 to Dec 31, 2007 7x24 @ $62.50/MWh Product B 450 MW - July 1, 2003 to Dec 31, 2007 275 MW - Jan 1, 2008 to Dec 31, 2010 6x16 @ $87.00 to $74.07/MWh Product C July 1, 2003 to Dec 31, 2010 50 MW 6x16 @ $70.00/MWh Contract terms: http://www.cers.water.ca.gov/power_contracts.cfm

CDWR Product D Resale of tolling rights Essentially, a mirror-image toll Term Jan. 2003 to Dec. 31, 2010 Quantity 1,175 MW through Dec. 31, 2007 1,045 MW through Dec. 31, 2010 Price $140/kW-year (to Dec. 31, 2007) to $117/kW-year (Jan. 1, 2008, to Dec. 31, 2010) Includes availability guarantees and potential penalties AES 4000 Offsetting Contracts Contract terms: http://www.cers.water.ca.gov/power_contracts.cfm

AES 4000 Transportation agreements cover 95% of 650,000 MMBtu/d peak need Kern: 107,625 MMBtu/d El Paso: 5,484 MMBtu/d SoCal: 506,794 MMBtu/d CDWR contract CDWR Product D contract gas management Fuel Management West

AES 4000 Locational Advantages AES 4000 generation "in-city" with premium Los Angeles locations Serves constrained load pocket Williams sells critical ancillary services to California ISO AES 4000-generated energy could benefit from accelerated schedule to enhance reserve margins and/or locational marginal pricing (LMP) No premium associated with LMP included in projections Development of capacity market WECC reserve margins not reflective of unique Southern California fundamentals

California Contract Expirations 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 CDWR 0 50 25 50 75 750 2000 1900 4900 100 QF 0 25 50 50 1000 0 1000 0 0 0 Utility 1100 0 1000 0 1000 3200 0 0 0 0 Source: CA PUC Staff Report, A Core/Noncore Structure for Electricity on California. March 15th 2004. P.19

Forward Spark-Spreads SP-15 (AES4000) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: Current curves presented above represent market conditions as of 9/30/2004 As of 9/30/04

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 Power Sale: Cleco Evangeline 100-250 MW Through 2005 Tolling: Kinder Morgan - Jackson 541 MW Through 2018 Portfolio Characteristics Mid-Continent

Forward power sales Capacity sold from Cleco Evangeline 250 MW through 2004 Call option from Cleco Evangeline 200 MW through 2004 100 MW through 2005 Offsetting Contracts Mid-Continent

Cleco Evangeline (Entergy) 145,000 MMBtu/d Columbia Gulf firm transportation capacity Peak day needs of 110,000 MMBtu/d 1 Bcf Egan (storage) KM Jackson (ECAR) 75,000 MMBtu/d full-requirements supply agreement Balancing account provided Gas Daily index price Fuel Management Mid-Continent

Forward Spark-Spreads Entergy (Cleco Evangeline) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: Current curves presented above represent market conditions as of 9/30/2004 As of 9/30/04

Forward Spark-Spreads ECAR/MI (KM Jackson) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: Current curves presented above represent market conditions as of 9/30/2004 As of 9/30/04

East

Portfolio Characteristics East Tolling agreements 2,276 MW 7,000 average heat rate Accounts for approximately 40% of approximately $400 million annual demand charges 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: TenaskaLindsay Hill 844 MW Through 2020

Offsetting Contract East - PJM Full requirements Agreement with Allegheny Electric Cooperative Not affiliated with Allegheny Energy Supply (AYE) Term December 2008 Capacity sold Approximately 600 MW peak demand

Offsetting Contracts East - SERC Full requirements 4 agreements with Walton, Colquitt, Satilla and Rayle EMCs Term December 2015 Capacity sold 600 MW in 2005, growing to 1,500 MW in 2015

Fuel Management East AES Ironwood (PJM) Peak daily requirement - 130,000 MMBtu/d 80,000 MMBtu/d no-notice supply agreement AES Red Oak (PJM) Peak daily requirement - 130,000 MMBtu/d 50,000 MMBtu baseload supply agreement Supplemental supply agreement Tenaska Lindsay Hill (SERC) Peak daily requirement - 110,000 MMBtu/d 65,000 MMBtu/d seasonal transportation agreement Hedging of heating oil fuel requirements

Forward Spark-Spreads PJM-West (Red Oak / Ironwood) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: Current curves presented above represent market conditions as of 9/30/2004 As of 9/30/04

Forward Spark-Spreads Southern (Tenaska) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: Current curves presented above represent market conditions as of 9/30/2004 As of 9/30/04

Financials & Accounting

Dollars in millions Estimated Demand Payment Coverage

Tolling cash flows associated with hedges Represents a percentage of the value of the underlying tolling option Includes value associated with optionality, such as volatility, that is not effectively hedged with all products; thus, actual cash flows may vary from estimates provided Merchant cash flows Represents unhedged cash flow from expected generation associated with underlying tolling option Includes value associated with optionality, such as volatility; thus, actual cash flows may vary from estimates provided Undiscounted Cash Flows Line Item Clarification

Total Undiscounted Cash Flows West Power Portfolio Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Also, please note that proprietary positions, storage, transportation, transmission, crude and refined products, interest rates, option premiums and margins are not included.

Total Undiscounted Cash Flows Mid-Continent Power Portfolio Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Also, please note that proprietary positions, storage, transportation, transmission, crude and refined products, interest rates, option premiums and margins are not included.

Total Undiscounted Cash Flows East Power Portfolio Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Also, please note that proprietary positions, storage, transportation, transmission, crude and refined products, interest rates, option premiums and margins are not included.

Undiscounted Cash Flows Variance Analysis Dollars in millions Dollars in millions Note: Q3 2004 forecast estimated as of 6/30/04. Combined Power Portfolio Actual Q3'04 v. Forecast Q3'04 3Q04 A 3Q04 F YTD'04 A YTD'04 F Tolling Demand Payment Obligations ($126) ($125) ($313) ($307) Resale of Tolling 29 25 105 102 Full Requirements 4 0 14 1 Long-term Physical Forward Power Sales 18 12 66 62 OTC Hedges 44 57 117 140 Merchant Cash Flows 80 93 121 124 Total Cash Flows $49 $62 $110 $122 Legacy Portfolio and Other Working Capital 281 37 456 32 Direct SG&A (13) (14) (35) (41) Indirect SG&A (7) (6) (21) (18) Estimated Cash Flows After SG&A $310 $79 $510 $95 3Q '04 Earnings Call

Key Terms & Definitions Accounting Methodologies Mark-to-Market Accounting is the process of estimating, recording, and reporting the fair value of physical and financial transactions. SFAS 133 requires that all derivatives be accounted for at fair value under mark-to- market accounting. Accrual Accounting is the process of measuring, recording and reporting transactions as they are realized, i.e. upon physical delivery or financial settlement. Hedge Accounting is a special election under SFAS 133 that allows unrealized gains/losses from designated derivatives to be recorded in OCI on the balance sheet rather than in earnings, and then reclassified from OCI to earnings in the same period in which the hedged item affects earnings. Normal Purchases & Sales Election under SFAS 133 allows certain derivative contracts to be accounted for under accrual accounting rather than mark-to- market accounting.

Key Terms & Definitions Derivatives Non-Derivative contracts are those not meeting SFAS 133 derivative criteria. Power's non-derivative contracts include tolling, full requirements, storage, transportation, and transmission. Non- derivative contracts may include executory contracts as well as leases. Derivative contracts are those which has all three of the following characteristics: One or more underlyings and one or more notionals Requires no initial investment or an initial net investment that is smaller than would be required for other contracts that would be expected to have a similar response to changes in market factors Its terms permit or require net settlement or involve delivery of an asset that can be readily convertible to cash (e.g. commodity).

Key Terms & Definitions Revenue-Related Terms Recognized Revenue is the amount of revenue reported or "recognized" in the financial statements for a given period. Recognized revenue may include both unrealized and realized revenue from both mark-to-market and accrual accounting. Unrealized Gains/Losses represent the changes in forward fair value of an instrument before that instrument has reached maturity. Realized Gains/Losses represent the amounts for which an instrument or transaction are ultimately settled once the deal has reached maturity or the transaction has occurred (physical delivery or service rendered). Prior to being realized, any gains or losses on derivatives are reported as unrealized. OCI represents "Other Comprehensive Income", a component of stockholders' equity in the balance sheet in which unrealized gains/losses from hedges are reported instead of in earnings, i.e. Under hedge accounting unrealized gains/losses are deferred in OCI instead of being recognized in earnings until the hedged transaction affects earnings.

Key Terms & Definitions Other Fair Value is the amount at which a financial instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale. Hedged Item is a either a recognized asset or liability or a forecasted transaction meeting certain criteria (e.g. future purchase of gas or future sale of power). Underlying a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable. An underlying may be a price or rate of an asset or liability but is not the asset or liability itself. Notional a number of currency units, shares, bushels, pounds, megawatts, MMBTU's, or other units specified in a derivative contract. Segment Profit After Mark-to-Market is a non-GAAP measure that Power reports outside of the financial statements in order to provide stakeholders with an alternative measure that estimates Power's segment profit if Power had never applied mark-to-market accounting, i.e. all unrealized gains/losses are reversed and all realized gains/losses are included in segment profit in the period in which realized.

SFAS 133 All derivatives recognized on balance sheet at fair value, and unrealized gains/losses on derivatives reported in earnings. Hedge accounting is an option, not a requirement. To elect hedge accounting, certain criteria must be met and formal hedge documentation required. Hedge accounting can only be elected on a prospective basis.

SFAS 133 To qualify for hedge accounting treatment, the derivative instruments must meet the following criteria: High historical correlation with instruments being hedged High prospective correlation with instruments being hedged High probability that forecasted hedged transactions will occur (i.e. if it is probable that an underlying contract/asset will be sold, the derivative instruments cannot qualify for hedge accounting treatment) Under hedge accounting unrealized forward gains and losses are deferred on balance sheet (OCI) until underlying is realized, thus earnings volatility is greatly reduced Note that an "economic hedge" does not always receive hedge accounting treatment

EITF 02-3 EITF 02-3 eliminated use of MTM accounting for all non-derivative contracts: Tolling Full requirements & load serving Storage Transportation Transmission These types of contracts are now accounted for on an accrual basis after January 1, 2003 charge for cumulative change in accounting principle.

EITF 02-3 Derivative instruments Financial transactions Options Swaps Futures Forward physical transactions Non-derivative instruments Tolling CDWR Product D Full requirements Storage Transportation Transmission Firm service Spot physical transactions

Other changes mandated by EITF 02-3 EITF 02-3 Before EITF 02-3 Inventory accounted for on MTM basis All trading revenues reported on a net basis After EITF 02-3 Inventory accounted for on a Lower of Cost or Market (LCM) basis Revenue reporting mixed Unrealized derivative revenues reported net Financially settled realized derivative revenues reported net Non-derivative revenues reported gross Physically settled realized derivative revenues reported gross

Normal Purchases & Sales Election Special election under SFAS 133 Permits certain qualifying derivative contracts to be accounted for on an accrual basis Elected for CDWR ABC & Gas contracts effective April 1, 2003 Fair value at time of election frozen on balance sheet and rolled-off as realized Subsequent changes in fair value not recognized

Dollars in millions (estimated as of 9/30/04) Future Hedge Realization 1Represents the fair value and expected future realization of those derivatives which qualify for hedge accounting under SFAS 133. Future changes in fair value will be reported in OCI on the balance sheet, and then re-classified into earnings in the period in which the hedged transaction, or underlying, affects earnings. 3Q '04 Earnings Call

Dollars in millions Derivative Net Asset Reconciliation Balance at 9/30/04 Power - Fair Value of Designated FAS 133 Hedges1 $979 Power - Other Derivatives (134) E&P - Fair Value of Designated FAS 133 Hedges (612) Corporate 12 Net Derivative Assets Per Balance Sheet $244 1Represents the fair value of those derivatives which qualify for hedge accounting under SFAS 133. Future changes in fair value will be reported in OCI on the balance sheet, and then re-classified into earnings in the period in which the hedged transaction, or underlying, affects earnings. 3Q '04 Earnings Call

Non-GAAP Reconciliation Schedule Dollars in millions except for per share amounts 2004 2003 1Q 2Q 3Q 1Q 2Q 3Q Recurring income from continuing operations available to common shareholders 3 $ 54 $ 136 $ (44) $ (12) $ (0) $ Recurring diluted earnings per common share 0.00 $ 0.10 $ 0.26 $ (0.08) $ (0.02) $ (0.00) $ Mark-to-Market (MTM) adjustments for Power: * Reverse forward unrealized MTM gains/losses (23) (69) (187) 40 (232) 54 Add realized gains/losses from MTM previously recognized 137 10 45 (55) 45 (45) Total MTM adjustments 114 (59) (142) (15) (187) 9 Tax effect of total MTM adjustments (at 39%) 44 (23) (55) (6) (73) 4 After tax MTM adjustments 70 (36) (87) (9) (114) 5 Recurring income from cont. operations avail. to common shareholders after MTM adjust. 73 $ 18 $ 49 $ (53) $ (126) $ 5 $ Recurring diluted earnings per share after MTM adjustments 0.14 $ 0.03 $ 0.09 $ (0.10) $ (0.24) $ 0.01 $ weighted average shares - diluted (thousands) 525,752 521,698 529,525 517,652 534,839 524,711 * Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. 3Q '04 Earnings Call

Mark to Market Adjustments Dollars in millions, except for per-share amounts 3rd Quarter YTD 2004 2003 2004 2003 Recurring income from continuing operations available to common shareholders 136 $ (0) $ 193 $ (56) $ Recurring diluted earnings per common share 0.26 $ (0.00) $ 0.37 $ (0.10) $ Mark-to-Market (MTM) adjustments for Power: 1 Reverse forward unrealized MTM gains/losses (187) 54 (279) (138) Add realized gains/losses from MTM previously recognized 45 (45) 192 (55) Total MTM adjustments (142) 9 (87) (193) Tax effect of total MTM adjustments (at 39%) (55) 4 (34) (75) After tax MTM adjustments (87) 5 (53) (118) Recurring income from cont. operations avail. to common shareholders after MTM adjustments 49 $ 5 $ 140 $ (174) $ Recurring diluted earnings per share after MTM adjustments 0.09 $ 0.01 $ 0.27 $ (0.33) $ (1) Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. Note: 2Q recurring income has been reduced by $16.5 mm (pretax) for Devil's Tower to reflect the third quarter change from recognizing revenues on the fixed fee received over a defined term to a units-of-production method that recognizes revenues as volumes are delivered for the life of the reserves. A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com. 3Q '04 Earnings Call

Segment Profit After MTM - Example Note: Assumes no hedge accounting treatment

Power Accounting Summary