Williams Power Tutorial Williams' intention to exit Interim liquidity characteristics and risk mitigation Accounting, earnings and valuation November 21, 2003

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.

Power Restructuring Outlook Actively pursuing full exit of power business Progress Sold or liquidated nearly $600 million of power-related assets and contracts since June 2002 Agreed to terminate contract with Allegheny Managing in the interim to Reduce risk Generate cash Meet contractual commitments Exit timing and value uncertain Remaining positions complex Power markets have deteriorated Value in West; little or negative value in remainder 3Q '03 Earnings Call

Tutorial Rationale Reinforce Williams' business strategy Integrated natural gas business Power is non core Disciplined focus on divesting non-core businesses Financial strategy is return to investment-grade credit characteristics by end of 2005 For Williams, Power is incompatible with regaining investment- grade credit Pursuing full exit of Power business

Tutorial Rationale Underscore current state of Power Williams' strategy regarding Power Increase transparency of business Reduce risk Generate cash Meet contractual commitments Exiting the business Progress to date is disappointing Current environment makes full, immediate exit difficult

Tutorial Rationale Underscore current state of Power continued Earnings Continues to play a significant role Continued volatility, related to accounting treatments Liquidity Manageable liquidity requirements YTD '03 - cash-flow positive, including sales Investors Perceived overhang

Tutorial Rationale Increase understanding of Williams' power portfolio, forecasted cash flows, risks Greater transparency New detail today Hedged positions and underlying contracts Expected cash flows - consolidated and by region Expected volumes (run rates) - consolidated and by region Spark-spread curves and sensitivities by region Business risks by region

Key Concepts Working toward full exit of Power Characteristics in the interim: Manageable liquidity requirements Contracts provide foundation to be cash flow positive through current down cycle Continued earnings volatility Current environment makes significant additional long-term hedging difficult Strategy in the interim: Increase transparency of business Reduce risk Generate cash Meet contractual commitments

Agenda Business overview Risks Regions West, Mid-Continent, East Positions, fundamentals, financials, risks Consolidated financials and sensitivities Accounting Legal and regulatory Q&A

Business Overview

Originator of short- and long- term structured transactions Point-of-view trading Third-party marketer 1,000 employees Principal growth driver Origination focused on selling unhedged MWs and capturing value from contracts Trading around assets and contractual positions Gas bought and sold to support existing power portfolio and WMB assets 225 employees Manage portfolio for cash flow, risk reduction until exit Power, Then and Now What it was: What it is now:

Characteristics Asset-based power business with long-term contractual commitments 6 tolling contracts Approximately 7,500 megawatts Approximately $400 million in annual demand charges 8 key offsetting contracts Estimated coverage of demand payment = 102% through 2010 (9/30/03)

Physical Natural Gas Average annual requirements 2.5 Bcf/d with peak of 3.5 Bcf/d 48% for Power 20% power-plant supply 28% third-party transactions 52% for Williams' core businesses Transportation 2.5 Bcf/d 35% for Power 65% for Williams' core businesses Storage 21 Bcf 67% for Power 33% for Williams' core businesses Improving market liquidity and credit

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 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 =

6 Tolling Contracts AES 4000 3,956 AES Ironwood 665 AES Red Oak 766 CLECO Evangeline 765 Kinder Morgan - Jackson 540 Tenaska - Lindsay Hill 844 7,536 Megawatts* * Subject to variation

Fixed Obligations & Estimated Cash Flows Estimated as of 9/30/03

Vehicles for Capturing Value from Tolling Contracts Resale of tolling rights Full requirements Physical forward power sales Standardized over-the-counter transactions All of the above contribute to total hedged tolling revenues

Resale of Tolling Rights Resale of all or part of Williams Power's rights under its tolling arrangements Example California Department of Water Resources (CDWR) Product D Essentially mirrors underlying tolling contract

Resale of Tolling Rights Estimated as of 9/30/03

Full Requirements Counterparty-tailored arrangement where Williams Power... Serves counterparty's load 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

Full Requirements Estimated as of 9/30/03

Physical Forward Power Sales Physical sale of a defined quantity of power over a set period of time Generally more standardized than resale of tolling rights or full requirements transactions Examples CDWR Products A, B and C CLECO Utility Group

Physical Forward Power Sales Estimated as of 9/30/03

Standardized OTC Transactions Physical and financial transactions (buys, sells, swaps, options) on industry-standard documentation (e.g., EEI, ISDA) Transactions vary from hourly to multi-year

Standardized OTC Transactions Estimated as of 9/30/03

Hedged Tolling Revenues Estimated revenues associated with hedges in place: Value against the underlying toll (versus market) Value for new transactions made possible by hedges (includes assumptions about markets and ability to execute) Actual cash flows may vary; hedges may not provide full protection for estimated tolling cash flows

Hedged Tolling Revenues Estimated Cash Flow Underlying Associated w/ Associated w/ Toll Market Hedge Toll* Hedge Net $25 $35 $35 $10 $0 $10 $25 $30 $35 $5 $5 $10 $25 $20 $35 $0 $15 $15 * Both the hedge and the underlying toll are marked against current market prices. Shown as Hedged Tolling Revenue on the following chart Example 1 Example 2 Example 3 Represents the estimated tolling revenues that have been hedged.

Hedged Tolling Revenue Estimated as of 9/30/03 $ Millions

Key Risks and Mitigation Efforts Liquidity requirements Reducing needs through sales of contracts, liquidation of portfolio components Market Hedged much of cash flows through '08 to reduce exposure to commodity price fluctuations Operational Counterparties contractually carry much of the operational risk associated with power plants Regulatory/Legal Ongoing market reviews Evaluations of power-grid regulation, development

Regional Portfolio - West

Overview of Positions Owned: Milagro 60 MW Natural-gas fired Tolling: AES 4000 3,956 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

AES 4000 Tolling Arrangement Capacity: 3,956 MW Term: June 2013 5-year option for either party to extend Annual demand payment: $151 million in '03 Escalates 1% annually until 2013 Approx. avg. portfolio heat rate: 10,100 Variable O&M payment $2.23/MWh in '03 Annual escalator is lesser of 2.5% or CPI 68% hedged until Jan. 2010 80% of total hedges with CDWR Contract terms: http://wwwcers.water.ca.gov/newContracts.html

AES 4000 Key Location 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 will benefit from highest locational marginal pricing (LMP) when implemented in 2005 Development of a market for capacity as a fungible commodity

AES 4000 - Offsetting Contracts CDWR Products A, B, C Forward power sale Product A July 1, 2003 to Dec 31, 2007 200 MW 7x24 @ $62.50/MWh Product B July 1, 2003 to Dec 31, 2010 175 MW to 450 MWs 6x16 @ $87.00 to $74.07/MWh Product C July 1, 2008 to Dec 31, 2010 50 MW 6x16 @ $70.00/MWh Contract terms: http://wwwcers.water.ca.gov/newContracts.html

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, '07 1,045 MW through Dec. 31, '10 Price $140/kW-year (to Dec. 31, '07) to $117/kW-year (Jan. 1, '08, to Dec. 31, '10) Includes availability guarantees and potential penalties Contract terms: http://wwwcers.water.ca.gov/newContracts.html AES 4000 - Offsetting Contracts

Market Fundamentals - California Williams Power Williams Power Baseload Demand Intermediate Demand Peaking Demand Baseload Demand Intermediate Demand Peaking Demand Supply Stack Scenarios Current price assumes $4.77. Supply stacks relevant only to unhedged portion of portfolio. Sources: Platt's, internal

Parameter Comparison Williams and CERA California Spark-Spread Curves Notes: Represents nominal data. CERA curve derived based on CERA information from CERA "Rear View Mirror" scenario. CERA data is copywritten and used only with expressed permission from CERA. No further use or redistribution is permitted. Spark spread represents the variable net margin per MWh of energy production Curves assume a 7 heat rate conversion efficiency and assume no Variable O&M costs Spark spread = power price - (7 x gas price)

Est. Cash Flows & Volumes - West Undiscounted Note: Does not include potential changes in working capital. Pre-Tax Estimated Cash Flows, Pre-SG&A, Non-Risk-Adjusted Actual Cash Flows may vary

Sensitivities - West 2003 2004 2005 2006-10 2011+ Variance (in $MM) 1.065544 16.49457 10.737547 99.39008 397.983865 Notes: As of 11/13/03. Sensitivities relevant only to unhedged portion of portfolio. $1 Increase in Spark Spreads $1 Decrease in Spark Spreads 2003 2004 2005 2006-10 2011+ Variance (in $MM) -0.149804 -7.839453 -1.729009 -63.211388 -340.344674

California Risks and Mitigation Efforts Political and/or regulatory interference Further challenges to CDWR contracts Price caps can limit upside during peak periods Re-regulation Mitigated by: New pro-business governor Williams settlement largely precludes further disputes over CDWR contracts Recent FERC decisions further validate CDWR contracts

California Risks and Mitigation Efforts Transmission build-out North to South (path 15 and path 26) expansion (1,500 MW; 400 MW) by 2005 Increases imports of cheaper hydro-, coal-generated energy Reduces congestion, dampens volatility, shrinks spark spreads Mitigated by: Threat of new transmission discourages/delays further capacity additions AES 4000 units still critical to L.A. grid integrity - transmission can't replace Short-term impact due to continuing load growth

California Risks and Mitigation Efforts New capacity additions New combined cycles operate more efficiently and cheaper then AES 4000 units (i.e., better heat rates and startup times) Mitigated by: Significant supply-demand gap still exists in California even if every contemplated project is built Unlikely in Los Angeles due to onerous siting/ permitting AES 4000 contract terms gives Williams the capability to compel the re-powering of existing AES 4000 units to stay competitive (a.k.a. "self-help provisions")

Regional Portfolio - Mid-Continent

Overview of Positions Tolling: Cleco Evangeline 765 MW Through 2020 Forward Power Sale: Cleco Evangeline 100-250 MW Through 2005 Tolling: Kinder Morgan - Jackson 540 MW Through 2018

Mid-Continent Portfolio Characteristics Tolling Agreements 1,305 megawatts 7,700 average heat rate Accounts for approximately 22% of Williams Power's approximately $400 million annual demand charges

Mid-Continent - Offsetting Contracts Physical Forward Power Sales Capacity sold from CLECO 250 megawatts through 2004 Call option from CLECO 200 megawatts through 2004 100 megawatts through 2005

Market Fundamentals - Mid-Continent Inter- mediate Demand Baseload Demand Peaking Demand Inter- mediate Demand Baseload Demand Peaking Demand Entergy Supply Stack Williams Power Williams Power Current price assumes $4.77. Supply stacks relevant only to unhedged portion of portfolio. Sources: Platt's, internal

Market Fundamentals - Mid-Continent Inter- mediate Demand Baseload Demand Peaking Demand Inter- mediate Demand Baseload Demand Peaking Demand Michigan Supply Stack (Kinder Morgan-Jackson) Williams Power Williams Power Current price assumes $4.77. Supply stacks relevant only to unhedged portion of portfolio. Sources: Platt's, internal

Parameter Comparison Williams and CERA Entergy Spark-Spread Curves Notes: Represents nominal data. CERA curve derived based on CERA information from CERA "Rear View Mirror" scenario. CERA data is copywritten and used only with expressed permission from CERA. No further use or redistribution is permitted. Spark spread represents the variable net margin per MWh of energy production Curves assume a 7 heat rate conversion efficiency and assume no Variable O&M costs Spark spread = power price - (7 x gas price)

Parameter Comparison Williams and CERA ECAR Spark-Spread Curves Notes: Represents nominal data. CERA curve derived based on CERA information from CERA "Rear View Mirror" scenario. CERA data is copywritten and used only with expressed permission from CERA. No further use or redistribution is permitted. Spark spread represents the variable net margin per MWh of energy production Curves assume a 7 heat rate conversion efficiency and assume no Variable O&M costs Spark spread = power price - (7 x gas price)

Est. Cash Flows & Volumes - Mid-Cont. Undiscounted Note: Note: Does not include potential changes in working capital. Pre-Tax Estimated Cash Flows, Pre-SG&A, Non-Risk-Adjusted Actual Cash Flows may vary

Sensitivities - Mid-Continent 2003 2004 2005 2006-10 2011+ Variance (in $MM) 0.041869 -0.203854 0.984944 9.824329 39.530788 $1 Increase in Spark Spreads $1 Decrease in Spark Spreads 2003 2004 2005 2006-10 2011+ Variance (in $MM) -0.018367 0.759449 -0.362124 -6.993604 -35.11945 Notes: As of 11/13/03. Sensitivities relevant only to unhedged portion of portfolio.

Mid-Continent Risks and Mitigation Efforts Entergy Generating capacity surplus - equilibrium > 2012-14 CLECO Evangeline combined-cycle tied to CLECO system Mitigated by: Transmission expansions to increase export capability Plant situated to serve CLECO load; provides reliability

Mid-Continent Risks and Mitigation Efforts ECAR Generating capacity surplus - equilibrium > 2010-12 New capacity additions still coming 4600 MW in 2004, 920 MW in 2005, 525 MW in 2006 Already embedded into price curves Mitigated by: Transmission expansions/reinforcements Increases export capability Improves transfer capability within region reduces congestion Plant retirements Development of an ancillary services market Creation of MISO

Regional Portfolio - East

Overview of Positions Full Requirements: Allegheny Electric Co-op 515-600 MW Through 2008 Tolling: AES Ironwood 665 MW Through 2021 Tolling: AES Red Oak 766 MW Through 2022 Owned: Hazleton 150 MW Natural gas-fired Full Requirements: Four Georgia EMCs 600-1,500 MW Through 2015 Tolling: Tenaska 844 MW Through 2020

East Portfolio Characteristics Tolling Agreements 2,275 megawatts 7,000 average heat rate Accounts for approximately 40% of Williams Power's approximately $400 million annual demand charges

East Portfolio - Offsetting Contracts Full Requirements Four agreements with Walton, Colquitt, Satilla and Rayle EMCs Term December 2015 Capacity sold 600 MW in 2005, growing to 1,500 MW in 2015 Sold Jackson EMC in March 2003 Sold at good value ($188 million) Risk-neutral Reduced credit requirements

East Portfolio - Offsetting Contract Full Requirements Agreement with Allegheny Electric Cooperative Not affiliated with Allegheny Energy Supply (AYE) Term December 2008 Capacity sold 515 to 600 MW

Market Fundamentals - East Intermediate Demand Baseload Demand Peaking Demand Intermediate Demand Baseload Demand Peaking Demand PJM Supply Stack (Red Oak and Ironwood Market Area) Williams Power Williams Power Current price assumes $4.77. Supply stacks relevant only to unhedged portion of portfolio. Sources: Platt's, internal

Market Fundamentals - East Intermediate Demand Baseload Demand Peaking Demand Intermediate Demand Baseload Demand Peaking Demand Southern Supply Stack (Tenaska Market Area) Williams Power Williams Power Current price assumes $4.77. Supply stacks relevant only to unhedged portion of portfolio. Sources: Platt's, internal

Parameter Comparison Williams and CERA PJM Spark-Spread Curves Notes: Represents nominal data. CERA curve derived based on CERA information from CERA "Rear View Mirror" scenario. CERA data is copywritten and used only with expressed permission from CERA. No further use or redistribution is permitted. Spark spread represents the variable net margin per MWh of energy production Curves assume a 7 heat rate conversion efficiency and assume no Variable O&M costs Spark spread = power price - (7 x gas price)

Parameter Comparison Williams and CERA Southern Spark-Spread Curves Notes: Represents nominal data. CERA curve derived based on CERA information from CERA "Rear View Mirror" scenario. CERA data is copywritten and used only with expressed permission from CERA. No further use or redistribution is permitted. Spark spread represents the variable net margin per MWh of energy production Curves assume a 7 heat rate conversion efficiency and assume no Variable O&M costs Spark spread = power price - (7 x gas price)

Est. Cash Flows & Volumes - East Undiscounted Note: Does not include potential changes in working capital. Pre-Tax Estimated Cash Flows, Pre-SG&A, Non-Risk-Adjusted Actual Cash Flows may vary

Sensitivities - East 2003 2004 2005 2006-10 2011+ Variance (in $MM) 0.368018 12.208492 5.236862 74.828851 415.059163 $1 Increase in Spark Spreads $1 Decrease in Spark Spreads 2003 2004 2005 2006-10 2011+ Variance (in $MM) -0.06266 -6.199246 0.771355 -47.993024 -367.058976 Notes: As of 11/13/03. Sensitivities relevant only to unhedged portion of portfolio.

East Risks and Mitigation Efforts PJM New capacity additions ~3000 MW in 2004, ~2000 MW in 2005 Mitigated by: Capacity additions completed by 2005 All capacity additions accounted for in price curves Equilibrium still expected to occur in 2008-10 timeframe Transmission constraints thwart further additions in load pockets Natural-gas infrastructure already inadequate Old, inefficient, expensive-to-operate steam plants will be "first to go"

East Risks and Mitigation Efforts PJM continued Physical restructuring impacts power-flow dynamics Transmission build-out Expansion of existing transmission connecting ECAR (Ohio) and VCAR (Virginia) to PJM (central Pa.) would increase import capacity into PJM-West Expansion of transmission connecting PJM-West to PJM-East would reduce congestion into key PJM load pocket Could delay equilibrium, dampen price volatility and collapse spark spreads Mitigated by: New transmission into NYC and Long Island Transmission bottlenecks throughout PJM Pressure on older, inefficient units to retire Siting new transmission along densely populated East Coast

East Risks and Mitigation Efforts Southern Generating capacity surplus - equilibrium > 2011/13 New capacity additions still coming 2700 MW in 2004, 1400 MW in 2005 Already embedded into price curves Mitigated by: Transmission expansions/reinforcements Increases export capability Improves transfer capability within region reduces congestion Plant retirements

Consolidated Financials

Est. Cash Flows & Volumes - Total Undiscounted Note: Does not include potential changes in working capital. Pre-Tax Estimated Cash Flows, Pre-SG&A, Non-Risk-Adjusted Actual Cash Flows may vary

Credit Characteristics - Total Portfolio Investment-grade counterparties make up >60% of total exposure Margining agreements are negotiated with counterparties where possible to mitigate credit risk with non-investment-grade counterparties

Sensitivities - Total Portfolio 2003 2004 2005 2006-10 2011+ Variance (in $MM) 1.475432 28.499208 16.959353 184.04326 852.573816 2003 2004 2005 2006-10 2011+ Variance (in $MM) -0.23083 -13.279249 -1.319778 -118.198015 -742.5231 $1 Increase in Spark Spreads $1 Decrease in Spark Spreads Notes: As of 11/13/03. Sensitivities relevant only to unhedged portion of portfolio.

Liquidity Volatility Margin volatility (99% confidence interval) - liquidity requirement 30 days $240 million 180 days $308 million 360 days $214 million Represents Williams Power and Williams' core natural gas businesses

Accounting

Revenue Recognition EITF 02-3 Adoption of EITF 02-3 on Jan. 1, 2003, requires: Non-derivative contracts be reported on an accrual basis Derivative contracts continue to be reported on a fair value basis under SFAS 133 Williams Power does not currently qualify for cash flow hedge accounting under SFAS 133 due to stated intent to exit the business

Revenue Recognition EITF 02-3 Prohibits the use of fair value accounting treatment for contracts that do not qualify as derivatives under FAS 133 "Accounting for Derivative Instruments and Hedging Activities" Derivative instruments: Underlying Notional Net settlement or instrument is readily convertible to cash Minimal net initial investment

Revenue Recognition 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

Revenue Recognition EITF 02-3 Since Williams Power does not currently qualify for cash flow hedge accounting... 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

Revenue Recognition EITF 02-3 GAAP earnings vary from economic results and cash flows: MTM gains or losses reflect change in fair value of derivative hedge portfolio, but not change in fair value of underlying non-derivative contracts such as tolling agreements Accrual earnings reflect earnings from underlying non-derivative contracts, but do not include previously recognized unrealized gains or losses from derivative contracts Normal purchases & sales contracts are no longer MTM but reflect realized accrual earnings offset by periodic reversal of previously recognized MTM earnings GAAP earnings are volatile because hedges are MTM without offsetting impact of change in fair value of underlying contract Cash flows provide proxy for accrual based economic results, but include changes in working capital

Other changes mandated by EITF 02-3 Revenue Recognition 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

Revenue Recognition - EITF 02-3 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 No Gross & Net Forward Physicals Derivative MTM No Gross & Net

Revenues include: Gross revenue for non-derivative contracts (eg., tolling) Gross revenue for realization of physically settled forward sales contracts Net revenues for changes in fair value of derivatives (unrealized gains and losses) Note: Changes in fair value of non- derivatives no longer reported Selling, General & Administrative Expenses Costs & op exps include: Demand payments Gross purchases for realization of physically settled forward purchases Income Statement: 2003 10-Q

Balance Sheet: 2003 10-Q Accounts Receivable: Commodity sales and derivative settlements Derivative Assets: Fair value (unrealized gains) of derivatives Margins: Margins, adequate assurance and prepays paid to others Note: Fair value of non-derivative contracts no longer reported on the balance sheet Accounts Payable: Commodity purchases Derivative Liabilities: Fair value (unrealized losses) of derivatives

Regulatory and Legal

Regulatory Perspectives Federal level RTOs will evolve and mature Evolution will be uneven regionally Price mitigation will constrain prices FERC will strengthen affiliate standards State level States will support rate-base generation RFPs will feature stakeholder participation and independent monitors Competitive bidding procedures will be formalized

Refund proceedings Filing due to FERC from CAISO and CalPX in March 2004 Natural gas trade information reporting Settlement reached with CFTC in July 2003 Ongoing DOJ investigation Trading practices Settlement being certified for approval by FERC Final decision expected late 2003 or early 2004 Ongoing investigation on physical and economic withholding Outstanding Legal Topics

CA/WA/OR settlement Effective as to state entities in Nov. 2002 Preliminary approval to include civil parties in settlement Final decision expected Feb. 2004 Outstanding Legal Topics Continued

Summary

Power Business - Key Concepts Intention to fully exit business $600 million liquidated to date, but progress is disappointing Market conditions make full, immediate exit difficult Efforts toward full exit continue Liquidity and risk mitigation Contracts provide foundation to be cash flow positive through current down cycle Cash flow positive year to date, including sales Continuing work to mitigate risk with additional hedges in the out years Accounting, earnings and valuation Required accounting treatments varied Continued earnings volatility, related to accounting treatments Estimated total undiscounted cash flows of $3 billion 2004-2022

Q&A