8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

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

June 10, 2004
(Date of earliest
event reported)

Commission File	Name of Registrant; State of Incorporation; Address of	IRS Employer
Number	Principal Executive Offices; and Telephone Number	Identification Number
1-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation)
	10 South Dearborn Street – 37th Floor
	P.O. Box 805379
	Chicago, Illinois 60680-5379
	(312) 394-7398
1-1839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation)
	10 South Dearborn Street – 37th Floor
	P.O. Box 805379
	Chicago, Illinois 60680-5379
	(312) 394-4321
1-1401	PECO ENERGY COMPANY	23-0970240
	(a Pennsylvania corporation)
	P.O. Box 8699
	2301 Market Street
	Philadelphia, Pennsylvania 19101-8699
	(215) 841-4000
333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company)
	300 Exelon Way
	Kennett Square, Pennsylvania 19348
	(610) 765-6900

TABLE OF CONTENTS

	Item 9. Regulation FD Disclosure
SIGNATURES
Slides and Handouts

Item 9. Regulation FD Disclosure

On June 11, 2004, Exelon Corporation (Exelon) will meet with investors and Merrill Lynch in Kennett Square, Pennsylvania. Attached as Exhibit 99 to this Current Report on Form 8-K are the slides and handouts to be used at the meeting.

This combined Form 8-K is being furnished separately by Exelon, Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (Registrants). Information contained herein relating to any individual registrant has been filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.

Certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants’ 2003 Annual Report on Form 10-K — ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants’ 2003 Annual Report on Form 10-K — ITEM 8. Financial Statements and Supplementary Data: Exelon — Note 19, ComEd – Note 15, PECO – Note 14 and Generation – Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

SIGNATURES

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

	EXELON CORPORATION
	COMMONWEALTH EDISON COMPANY
	PECO ENERGY COMPANY
	EXELON GENERATION COMPANY, LLC
	/s/ Robert S. Shapard
	Robert S. Shapard
	Executive Vice President and
	Chief Financial Officer
	Exelon Corporation
June 10, 2004

EX-99

Exhibit 99

Power Marketing Overview Merrill Lynch Investor Meeting Kennett Square June 11, 2004 Exelon Corporation

This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants' 2003 Annual Report on Form 10-K-ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants' 2003 Annual Report on Form 10-K-ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 19, ComEd- Note 15, PECO-Note 14 and Generation-Note 13, and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Registrants). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. Forward-Looking Statements

Welcome/Agenda 9:00 - 9:15 Bob Shapard, EVP & CFO Power Marketing Overview 9:15 - 9:30 Ian McLean, EVP & President, Power Team Portfolio Management 9:30 - 10:15 Ken Cornew, SVP, Power Transactions POLR Pricing 10:15 - 11:15 Mike Freeman, Power Transactions Shravan Chopra, Manager, Pricing Post Transition Regulatory 11:15 - 12:00 Anne Pramaggiore, VP, ComEd Regulatory Update Lisa Crutchfield, VP PECO Regulatory Break 12:00 - 12:15 Lunch Long-Term Marketing: 12:15 - 12:45 John Young, SVP & President, Exelon Power Laura Raymond, VP, Marketing & Bus. Dev. Market Fundamentals: 12:45 - 1:30 Jim Lockhart, Fuels Forecasting Bruce Lamson, Manager, Market Planning Trade Floor Tour: 1:30 - 2:00 Walt Kuhn, Director, Power Transactions AGENDA - Merrill Lynch Investor Meeting

Context for Today's Discussion

Key Message: Exelon is well positioned for end of transition periods in Illinois and Pennsylvania Divesting underperforming assets Driving strong earnings and cash flow growth through Exelon Way Strong credit position Large, low-cost base load generator Large, stable retail customer base Recovering / expanding wholesale markets Fully engaged with all our stakeholders Incorporating lessons learned from Mid-Atlantic markets

ComEd Bundled Tariff for Mass Market 2003 Actual* 2007 Estimate RES SCI LCI LCI (< 3 MW) Non-Wires Rate 49 43 49.9 49.9 48.9 28 Line Losses 3 3 Wires Rate 25 31 35.1 15.1 10.1 3 77 77 Assumes 25% increase in wires charges to recover increased investment in transmission and distribution infrastructure and costs. * Representative of unbundling of existing tariff. ** Includes the cost of energy, capacity, ancillary services, load following, weather, switching and congestion. Note: Mass Market represents residential and small commercial and industrial customer classes. ** **

Power Team: Value Added Intermediary Nuclear Fossil Hydro Generation Exelon Power Team ComEd PECO Wholesale Power & Fuel Markets Affiliates Contracts Power Team manages the interaction between the generation portfolio and the wholesale customers in order to reduce risk and optimize Exelon Generation profitability in the near term.

Power Marketing Overview Exelon Planning Corporate Strategy Mkt. Fundamentals Power Marketing Portfolio Mgt. Power Transactions Fuels Transactions Long-Term Mktg. Trade Floor Mgt. Operations Acct'g & Finance Financial Reporting Mgt. Analysis Risk Quantification Risk Control Risk Control Credit Management Legal Oversight

Portfolio Management Current Position Risk Control Process

Midwest Portfolio Characteristics *Assuming $6.30/MMBtu gas price Indiana Illinois Chicago Portfolio Opportunities / Challenges Recent integration into PJM market will add liquidity to the standard and structured product markets Length from base load units to participate in higher market prices Load following capability is purchased from third parties and the power pool Lack of liquidity in off-peak market creates a challenge for portfolio management 18,375 Peak Load (MW) 74,000 Annual GWh (2004) Demand - PPA 20,907 Total Capacity $ 75.00 4,481 Peakers* $ 34.00 1,084 Intermediate $ 20.00 4,456 Coal $ 4.50 10,886 Nuclear Avg. Variable Cost ($/MWh) Plant 2004 Capacity (MW)

Pennsylvania Maryland New Jersey Delaware Mid-Atlantic Portfolio Characteristics * Assuming $6.30/MMBtu gas price Plant 2004 Capacity (MW) Average Variable Cost ($/Mwh) Nuclear 5,743 5.00 Hydro 1,611 NA Coal 1,453 $34.00 Intermediate/NUG 250 $50.00 Peakers 2,108 $65 resid oil / $100 gas Total Capacity 11,165 Demand - PPA Annual (Gwh) (2004) 34,600 PPA Peak Load (MW) 6,950 Portfolio Opportunities / Challenges We operate in a centrally dispatched power pool More liquidity in the PJM region creates more capability to hedge CCGTs are on the margin for a majority of the on-peak hours and many of the summer off-peak hours Length from base load units to participate in higher market prices Capability to follow load is dependent on structured transactions and utilization of the pool

ERCOT/South Portfolio Characteristics Plant Capacity Average Variable Cost ($/Mwh) Combined Cycle* 1,975 MW $50.50 Peakers* 3,394 MW $75.00 Total Capacity 5,369 MW Summer Toll** 2,334 MW * Assuming $6.30/MMBtu gas price ** TXU tolling deal totaling 2,334 MW Texas Oklahoma Georgia Portfolio Opportunities / Challenges The portfolio assets are in the ERCOT, SPP and SERC regions The combined cycle units are generally hedged forward; remaining length and peaker length used for opportunistic sales ERCOT ISO often runs the peakers for local reliability reasons

Portfolio Management Process Approach to Portfolio Management Over Time Time Before Expiration of Contract % Hedged % Hedged High End of Profit Low End of Profit Load Only Long View Long-Term Portfolio Balancing Portfolio Optimization and Risk Management Operating Profit ($ Million) Develop a set of relevant commercial options to manage portfolio based on realistic market opportunities Evaluate options on following criteria: Gross margins Risk Reduction Credit Implications Commercial Viability Outputs: Near-term portfolio plan Portfolio management parameters, such as strategic gross margin and risk targets Inputs: Current Positions Market Prices, volatilities, correlations Commercial Dynamics: liquidity, active counterparties, products, credit Near-term market perspective Physical Constraints Corporate targets: earnings, risk Timing of portfolio process Update the portfolio plan quarterly Monitor parameters weekly Approach to managing volatility Increase percentage hedged as delivery approaches Have enough supply to meet peak load Cover options created by load obligations so that base load length can be sold Leave some length to spot for operational uncertainties and opportunistic sales Purchase Coal, Oil, and Natural Gas as power is sold

Portfolio Management Q&A

POLR Pricing Competitive Procurement Model Lessons from NJ BGS Auction Price Build-up

Current Model Utility Genco Base Intermed Peak Customers <1MW Hours Genco is sole supplier of customer (<1MW) load through a PPA with ComEd Genco/ComEd PPA Bundled Rate Customer Load (<1MW)

Competitive Procurement Model Competitive Suppliers Utility Genco Base Intermed Peak Customers <1MW - - Load up for auction XX% XX% XX% Hours Vertical Slices of System Load Multiple winning bidders would supply customer load in vertical slices (fixed % of hourly energy demand) New rates determined by auction results Clock Auction Rate Options

BGS Auction Basic Generation Service (BGS): Over 11,000 MW of load auctioned across 4 utilities in New Jersey in Feb 2004 Over 15 winners in the auctions Winning bids were at 50-60% "adder" over the standard block product Overview Risk management of the BGS full requirement contracts for the winners was critical - - Gas and power prices spiked significantly after the auction Congestion risk needs to be managed largely through physical assets within the congested zone Market liquidity has an impact on the "adders" over the standard block product - - Limited liquidity in the Midwest as compared to PJM likely to increase "adder" of full requirement contracts Lessons Learned

Full Requirements Contracts Components of a Full Requirements Price A. Underlying Energy - Standard Block Energy Price - Load Shape Price - Volume Risk B. Customer Migration Risk C. Capacity Price D. Ancillaries Price E. Other Risks - Transmission (Congestion) - Credit - Regulatory Components of a Typical Full Requirements Contract POLR (Provider of Last Resort) is a Full Requirements Contract Delivering party takes all obligations associated with serving a load at a fixed price Obligations include energy, capacity and ancillary services Delivering party assumes all the risks in the full requirements contract including customer migration risk

Risk Management of Full Requirements Forecasted Load and Underlying Energy Curve Actual Load and Underlying Energy Curve Standard Block Products Expected Load Shape Long Short Standard Block Products Actual Load Shape Shorter Longer Forecast............. One of numerous realities........ - Regulatory - Credit - Congestion E. Other Risks D. Ancillaries Price C. Capacity Price B. Customer Migration Risk - Volume Risk - Load Shape Price - Standard Block Energy Price A. Underlying Energy Components of a Full Requirements Price Contractual management Contractual risk management Congestion related options / local supply Buy ancillary services / self supply Buy capacity / self supply Option strategies Option strategies / self supply Buy shaped products / self supply Buy standard blocks / self supply Risk Management Strategy High High Medium Low High High Medium High Low Level of Risk Mitigation

POLR Pricing Q&A

Post-Transition Regulatory Update ComEd PECO

ICC Post-2006 Overview Education Process Consensus Development Scenario Analysis ICC Process Launch Stakeholder Positions Identified Key Milestones: ICC Workshop Process finalized 4/1 5 Working Groups and conveners appointed Procurement - Dave Vite, IRMA Rates - Glenn Rippie, Foley & Lardner Competition - Phil O'Connor, New Energy Service Obligations - Mark Pera, CCSA Energy Assistance - Jim Monk, IEA Comments filed with ICC 4/22 ICC Kick-off Symposium 4/29 Key Milestones: Scenarios Developed and Explored: - NJ/Md - Horizontal/IRP - Rate Freeze - Affiliate Full Requirements - Return to regulation Joint Working Group Session 6/22 - 6/23 - RTO discussion - State Model Panel discussion NJ Md Texas Montana California Key Milestones: Working Groups Report to ICC Commission Report to General Assembly identifying areas of consensus Key Milestones: Issues Analysis - Working Groups develop response to 93- item Issues List April - May '04 June '04 July '04 August '04 September-November '04 Key Milestones: Developing Consensus positions Commission Report

Stakeholder Positions (based on comments) Continuum of State Restructuring Models Texas New Jersey / Maryland Reliant ComEd Ameren Labor Mirant Mid American Midwest Gen CUB AG City Cook County Ohio California / Montana

PA PUC POLR Timeline Roundtable Announced Roundtables 1 & 2 Roundtables 3 & 4 Final Roundtable POLR Rulemaking Process Milestones: 3/4 - Motion of Comm. Thomas to initiate Roundtables. 3/18 - PUC Issues Secretarial Letter and POLR Issues List. Milestones: 4/5 - Deadline for Interested Parties to notify PUC. 4/8 - 1st Roundtable FERC PJM NJ BPU MD PSC CAEM 4/21 - 2nd Roundtable-EDC's PECO Energy PPL FirstEnergy Duquesne Allegheny UGI Milestones: 5/3 - 3rd Roundtable Retail Marketers 5/19 - 4th Roundtable Wholesale Marketers Exelon Generation Other Generators Milestones: 6/2 - 5th Roundtable Consumer Groups OCA OSBA PAIEUG Penn Futures AFL/CIO Milestones: Fall '04/Winter '05 PUC drafts & issues Proposed Rulemaking 2005-2006 Rulemaking Process March '04 April '04 May '04 June '04 Fall '04/Winter '05

Major PA Utilities Post Transition Dates 1/1/05 1/1/07 1/1/09 1/1/10 1/1/11 Duquesne (11%) Penn Power (3%) Allegheny Power (13%) PP&L (24%) PECO Energy (29%) Pennelec (11%) MetEd (9%) [Duquesne (11%)] Proposed stipulation "extends" Post-Transition to 1/1/11. Post-Transition for almost 75% of customers does not start until after 1/1/10. With Duquesne settlement, Post-Transition customer percentage = 86%. (Includes percentage of customers served in Pennsylvania)

PA POLR Generation Procurement Models Cost of Service Purchased Power Agreements (PPA) UGI Duquesne Request for Proposal (RFP) (Maryland) Allegheny Power Amerada Hess Calpine Citizens Power Wellsboro Electric Horizontal Auction Full Requirements/ Vertical Auction (NJ Model) PPL FirstEnergy (EDC) DTE Energy Select Energy Amerada Hess Mirant [ComEd] Supports a competitive process but does not advocate a specific model: Constellation • Reliant PPL Energy Plus • NEMA Morgan Stanley/J. Aron • Dominion PECO Energy - Advocates generation procurement through competitive models ranging from purchased power agreements to vertical auctions. Source: Company Submission to PA PUC POLR Roundtable

4 2.41 0.45 2.43 4.55 5 2.41 0.45 2.4 4.58 6 2.53 0.45 2.66 4.85 7 2.53 0.45 2.66 5.35 8 2.53 0.45 2.66 5.35 9 2.53 0.45 2.66 5.35 10 2.53 0.45 2.66 5.35 Electric Restructuring & Merger Settlements Energy & Capacity CTC Transmission Distribution 9.96¢ 9.84¢ 9.84¢ + 7% 10.49¢ + 5% 10.99¢ 10.99¢ 10.99¢ 10.99¢ Source: 1998 Restructuring Settlement Unit Rates (¢/kWh)

Post-Transition Regulatory Update Q&A

Market Fundamentals Underlying Fuel Prices Reserve Margins Power Price Forecasts

Electricity demand is expected to grow at more than 2% per year for the rest of the decade based on the forecast of underlying GDP. Load growth is projected to be stronger in the South and West, and will follow new construction. Fuel prices are higher than they were in the 1990's, and are unlikely to return to the same low levels. Strong demand and little excess supply have allowed headlines to drive oil prices higher. High oil prices and a tight domestic supply cause high gas prices, but LNG may provide relief by the end of the decade. Coal spot market prices have increased sharply over the last year, but are likely to decline over time as capacity increases. Economic Growth and Fuels Overview

GDP GDP Forecast Electricity Use Electricity Use Forecast 1995 0.02504315 0.028897282 1996 0.037003352 0.028388904 1997 0.04497594 0.014491889 1998 0.041750445 0.039795904 1999 0.04449988 0.020281682 2000 0.036598447 0.031500531 2001 0.005065204 -0.014115574 2002 0.021929911 0.029882021 2003 0.031233099 0.031233099 0.052860539 0.052860539 2004 0.046831907 0.024878187 2005 0.03486053 0.024307136 2006 0.037146209 0.02207815 2007 0.038079904 0.021200369 2008 0.033397852 0.020548164 2009 0.030731081 0.017470379 Robust economic growth will drive load higher Load will grow at about 70% the rate of regional economic expansion, and is expected to grow strongest in the South and West. GDP forecast from Economy.com; historical ratio of load growth to GDP

Gas PIRA CERA NYMEX 2000 27.25947 Feb _2000 29.366 Mar_2000 29.84174 Apr_2000 25.72211 May_2000 28.78818 Jun_2000 31.82227 Jul_2000 29.69684 Aug_2000 31.26391 Sep_2000 33.884 Oct_2000 33.10864 Nov_2000 34.41714 Dec_2000 28.4365 2001 29.58571 Feb _2001 29.60947 Mar_2001 27.24455 Apr_2001 27.49 May_2001 28.62909 Jun_2001 27.59905 Jul_2001 26.42476 Aug_2001 27.37391 Sep_2001 26.19947 Oct_2001 22.16957 Nov_2001 19.635 Dec_2001 19.38895 2002 19.71476 Feb _2002 20.72368 Mar_2002 24.531 Apr_2002 26.17909 May_2002 27.04136 Jun_2002 25.5185 Jul_2002 26.96619 Aug_2002 28.385 Sep_2002 29.66 Oct_2002 28.84 Nov_2002 26.35 Dec_2002 29.46 2003 32.95 Feb _2003 35.83 Mar_2003 33.51 Apr_2003 28.17 May_2003 28.11 Jun_2003 30.66 Jul_2003 30.75 Aug_2003 31.57 Sep_2003 28.31 Oct_2003 30.34 Nov_2003 31.11 Dec_2003 32.13 2004 34.31 Feb _2004 34.68 Mar_2004 36.74 Apr_2004 36.75 May_2004 40.28 Jun_2004 41 41 41 Jul_2004 43 37.8 39.28 Aug_2004 43.6 35.24 39.23 Sep_2004 44.02 33.192 39.02 Oct_2004 44.314 31.5536 38.61 Nov_2004 44.5198 30.24288 38.16 Dec_2004 44.56782 29.194304 37.71 Jan_2005 44.611038 28.3554432 37.21 Feb _2005 44.65915641 27.68435456 36.76 Mar_2005 44.70732672 27.14748365 36.39 Apr_2005 44.75554899 26.71798692 36.03 May_2005 44.80382328 26.37438953 35.7 Jun_2005 44.85214963 26.09951163 35.41 Jul_2005 44.90052811 25.8796093 35.16 Aug_2005 44.94895877 25.70368744 34.94 Sep_2005 44.99744167 25.56294995 34.72 Oct_2005 45.04597687 25.45035996 34.52 Nov_2005 45.09456441 25.33826586 34.32 Dec_2005 45.14320437 25.22666548 34.12 2006 45.19189678 25.11555663 33.89 Feb _2006 45.24064172 25.00493714 33.69 Mar_2006 45.28943924 24.89480488 33.5 Apr_2006 45.33828938 24.78515768 33.34 May_2006 45.38719222 24.67599341 33.18 Jun_2006 45.43614781 24.56730995 33.02 Jul_2006 45.4851562 24.45910518 32.86 Aug_2006 45.53421746 24.35137699 Sep_2006 45.58333163 24.24412328 Oct_2006 45.63249878 24.13734195 Nov_2006 45.68171896 24.03103094 Dec_2006 45.73099223 23.92518817 Jan_2007 45.78031865 23.81981157 Feb _2007 45.82969827 23.71489909 Mar_2007 45.87913115 23.6104487 Apr_2007 45.92861736 23.50645834 May_2007 45.97815694 23.40292601 Jun_2007 46.02774995 23.29984967 Jul_2007 46.07739646 23.19722733 Aug_2007 46.12709651 23.09505698 Sep_2007 46.17685018 22.99333663 Oct_2007 46.22665751 22.8920643 Nov_2007 46.27651856 22.79123801 Dec_2007 46.32643339 22.69085581 2008 46.37640207 22.59091573 Feb _2008 46.42642464 22.49141583 Mar_2008 46.47650116 22.39235417 Oil prices are currently high and will be slow to fall Oil prices are caught between slowly growing non-OPEC supply and strong demand, particularly from China and U.S. gasoline. Little excess world productive capacity and threats to supply leads to high volatility and possible price spikes. High prices will be self-correcting, as sustained prices above $35 will slow economic growth. While there is no "next new thing", production from existing basins could be expanded. NYMEX Forecasts 2004 2005 2006 EIA $36.39 $34.52 PIRA $38.30 SEER $34.31 $27.87 $25.91 The tight world oil market raises the floor for natural gas prices, and also may serve as a brake on the economy. Upper Bound Lower Bound

Gas Oil PIRA CERA NYMEX 2000 4.699908621 2.40925 Feb _2000 5.063103448 2.6555 Mar_2000 5.145127586 2.791522 Apr_2000 4.434846552 3.030158 May_2000 4.96347931 3.580909 Jun_2000 5.486598276 4.284091 Jul_2000 5.120144828 3.973684 Aug_2000 5.39032931 4.418478 Sep_2000 5.842068966 5.0579 Oct_2000 5.708386207 5.023636 Nov_2000 5.933989655 5.53125 Dec_2000 4.902844828 8.9356 2001 5.100984483 8.160476 Feb _2001 5.105081034 5.577895 Mar_2001 4.697336207 5.169 Apr_2001 4.739655172 5.1815 May_2001 4.93605 4.193182 Jun_2001 4.758456897 3.731714 Jul_2001 4.555993103 3.10381 Aug_2001 4.719639655 2.958478 Sep_2001 4.51715 2.192632 Oct_2001 3.822339655 2.464565 Nov_2001 3.385344828 2.37975 Dec_2001 3.342922414 2.416842 2002 3.399096552 2.266905 Feb _2002 3.573048276 2.302632 Mar_2002 4.229482759 3.029 Apr_2002 4.513636207 3.441 May_2002 4.662303448 3.492727 Jun_2002 4.399741379 3.22775 Jul_2002 4.649343103 2.980238 Aug_2002 4.893965517 3.085909 Sep_2002 5.113793103 3.55375 Oct_2002 4.972413793 4.122174 Nov_2002 4.543103448 4.046579 Dec_2002 5.079310345 4.743571 2003 5.681034483 5.44 Feb _2003 6.177586207 7.8 Mar_2003 5.777586207 5.94 Apr_2003 4.856896552 5.24 May_2003 4.846551724 5.81 Jun_2003 5.286206897 5.88 Jul_2003 5.301724138 5.15 Aug_2003 5.443103448 5.02 Sep_2003 4.881034483 4.62 Oct_2003 5.231034483 4.66 Nov_2003 5.363793103 4.435 Dec_2003 5.539655172 6.15 2004 5.915517241 6.05 Feb _2004 5.979310345 5.37 Mar_2004 6.334482759 5.39 Apr_2004 6.336206897 5.7 May_2004 6.944827586 6.3 Jun_2004 7.068965517 6.5 6.5 6.5 Jul_2004 6.8 5.9 6.363 Aug_2004 7.01 5.48 6.411 Sep_2004 7.157 5.186 6.413 Oct_2004 7.2599 4.9802 6.435 Nov_2004 7.33193 4.83614 6.62 Dec_2004 7.348737 4.802526 6.81 Jan_2005 7.3638633 4.7722734 6.94 Feb _2005 7.37747697 4.74504606 6.89 Mar_2005 7.389729273 4.720541454 6.71 Apr_2005 7.404508732 4.698487309 6.055 May_2005 7.419317749 4.678638578 5.885 Jun_2005 7.434156385 4.66077472 5.893 Jul_2005 7.449024697 4.644697248 5.923 Aug_2005 7.463922747 4.630227523 5.938 Sep_2005 7.478850592 4.607076385 5.9 Oct_2005 7.493808293 4.584041003 5.915 Nov_2005 7.50879591 4.561120798 6.08 Dec_2005 7.523813502 4.538315194 6.255 2006 7.538861129 4.515623618 6.37 Feb _2006 7.553938851 4.4930455 6.32 Mar_2006 7.569046729 4.470580273 6.12 Apr_2006 7.584184822 4.448227372 5.518 May_2006 7.599353192 4.425986235 5.365 Jun_2006 7.606952545 4.403856303 5.355 Jul_2006 7.614559498 4.381837022 5.365 Aug_2006 7.622174057 4.359927837 5.383 Sep_2006 7.629796231 4.338128198 5.348 Oct_2006 7.637426027 4.316437557 5.363 Nov_2006 7.645063453 4.294855369 5.533 Dec_2006 7.652708517 4.273381092 5.698 Jan_2007 7.660361225 4.252014187 Feb _2007 7.668021587 4.230754116 Mar_2007 7.675689608 4.209600345 Apr_2007 7.683365298 4.188552343 May_2007 7.691048663 4.167609582 Jun_2007 7.698739712 4.146771534 Jul_2007 7.706438451 4.126037676 Aug_2007 7.71414489 4.105407488 Sep_2007 7.721859035 4.08488045 Oct_2007 7.729580894 4.064456048 Nov_2007 7.737310475 4.044133768 Dec_2007 7.745047785 4.023913099 2008 7.752792833 4.003793533 Feb _2008 7.760545626 3.983774566 Mar_2008 7.768306171 3.963855693 Gas prices driven by oil prices and mature resources Natural gas prices have been following world oil prices over the last five years. Despite higher prices, domestic gas production has been trailing supply. 2004 demand YTD has been balanced by roughly 1 Bcf/Day additional LNG, but we are reaching limits of current capacity. Market remains vulnerable to seasonal disruptions and winter price spikes. New LNG could lead to a new lower equilibrium, but not until 2007. NYMEX Historical Gas Historical Oil Forecasts 2004 2005 2006 EEA $5.60 $6.90 PIRA $6.39 $6.53 $5.73 CERA $5.83 $6.02 SEER $5.71 $5.74 $5.26 Strong generation demand, constrained domestic supply, and limits on imports will keep gas prices high and linked to oil until new LNG built. Upper Bound Lower Bound

2000 4.375 24.14 2001 9.3375 40.41 2002 5.85 29.65 2003 6.2125 6.2125 6.2125 31.1 31.1 31.1 2004 8 5.8625 48 35 2005 8.07 5.41375 48.96 33.25 2006 8.15 5.3375 49.9392 31.5875 2007 8.344386736 4.930213729 50.937984 30.008125 2008 8.360924014 4.747415735 51.95674368 28.50771875 2009 8.225807106 4.487659189 52.99587855 27.08233281 Coal prices have climbed sharply in the East Northern Appalachian Coal 13.1K BTU/Ton, 1.6% Sulfur Coal prices have grown sharply in the last year. International demand growth Production decline Cold, wet winter Limited substitution Prices reflect a short-term supply and demand imbalance, and should fall with capacity increases. Forecasts NAPP 2004 2005 2006 JDE $43.15 $36.45 $31.57 H&A $42.00 PRB 2004 2005 2006 JDE $7.28 $7.34 $7.21 H&A $7.20 PIRA $7.90 Tight coal markets will lead to more domestic production, but prices will remain high until mining, transportation and consumption can respond. Powder River Basin Coal 8.8K BTU/Ton, 0.35% Sulfur Upper Bound Upper Bound Lower Bound Lower Bound

PJM Eastern Region reserve margin drops below 15% by 2007 3,500 MW of new Combined Cycle Gas Turbine (CCGT) generation expected to enter market 2004 - 2005; 1,900 MW of older inefficient generation expected to retire Average annual net imports expected to be ~1,700 MW in 2005, declining to ~1,000 MW by 2009. PJM imports economic energy from ECAR, while exporting to New York Market prices strongly influenced by natural gas during on-peak period and by coal-fired generation during off-peak period MAIN Market reserve margin drops below 15% by 2008 2,300 MW of new CCGT generation expected to enter market 2004 - 2005 Average annual net exports expected to be ~3,000 MW through 2009. MAIN sub regions Wisconsin and Alliant West have low reserve margins and rely on economic imports. ComEd market exports economic energy to both ECAR to the east and Wisconsin to the North. Near-term prices have increased substantially, driven by higher fuel (gas and coal) prices. Supply fundamentals and pricing Supply fundamentals Market Overview - Key Messages The current wave of new supply is coming to a close. The next cycle of new supply need will be here by the end of this decade.

Supply fundamentals and pricing Supply fundamentals PJM East Region - Supply Curve Cumulative Supply (MW) Reserve Margin (%) Load will increasingly be met by higher cost generation, fueled by volatile natural gas and oil. Exelon Generation Forecast: April, 2004 Note: HR = Heat rate

needs Needs Supply fundamentals and pricing Supply fundamentals PJM East Region - Consultant Forecasts Source: Platts Research and Consulting Outlook For Power in North America, Quarter 1 2004 CERA New Realities, New Risks: North American Power and Gas Scenarios (December 2003) ATC Energy and Capacity ($/MWh) Implied Heat Rate (Btu/kWh) and Delivered Gas Price ($/MMBtu) Industry price forecasts are driven by load growth, retirements, and fuel prices.

Supply fundamentals and pricing Supply fundamentals MAIN Market - Supply Curve Cumulative Supply (MW) Reserve Margin (%) Energy prices will be influenced increasingly by higher variable cost supply. Capacity prices will strengthen over time as reserve margins decline. Exelon Generation Forecast: April, 2004 Note: HR = Heat rate

needs Needs Supply fundamentals and pricing Supply fundamentals Energy and Capacity ( $/MWh) Implied Heat Rate (Btu/kWh) and Delivered Gas Price ($/MMBtu) MAIN Market - Consultant Forecasts Industry price forecasts are driven by load growth, retirements, and fuel prices. Source: Platts Research and Consulting Outlook For Power in North America, Quarter 1 2004 CERA New Realities, New Risks: North American Power and Gas Scenarios (December 2003)

Market Fundamentals Q&A