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Safe Harbor Language This presentation includes "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, for example, statements regarding benefits of the proposed merger of Exelon and PSEG, integration plans, and expected synergies, anticipated future financial and operating performance and results, including estimates for growth. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements made herein. A discussion of some of these risks and uncertainties, as well as other risks associated with the proposed merger, is included in the preliminary joint proxy statement/prospectus contained in the Registration Statement on Form S-4 (Registration No. 333-122704) that Exelon has filed with the Securities and Exchange Commission. Additional factors that cause actual results to differ materially from the forward-looking statements made herein are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Outlook and the Challenges in Managing the Business" in Exelon's 2004 Annual Report on Form 10-K. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Neither Exelon nor PSEG undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

Additional Information This presentation is not a solicitation of a proxy from any security holder of Exelon or PSEG. The above- referenced Registration Statement on Form S-4 contains a preliminary joint proxy statement/prospectus and other relevant documents regarding the proposed merger of Exelon and PSEG. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE PROPOSED TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT EXELON, PSEG AND THE PROPOSED MERGER. Investors and security holders will be able to obtain these materials (when they are available) and other documents filed with the SEC free of charge at the SEC's website, http://www.sec.gov. In addition, a copy of the definitive joint proxy statement/prospectus (when it becomes available) may be obtained free of charge from Exelon Corporation, Shareholder Services, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680- 5398, or from Public Service Enterprise Group Incorporated, Investor Relations, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey 07101-1171. The respective directors and executive officers of Exelon and PSEG and other persons may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding Exelon's and PSEG's directors and executive officers and other participants in the solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is available in the preliminary joint proxy statement/prospectus contained in the above-referenced Registration Statement on Form S-4.

2004 Financial Summary $2.78 Operating EPS (+6.5% over 2003) Core growth in retail volumes Higher generation margins Acquisition of the second half of AmerGen Exelon Way cost savings Reduced losses at Enterprises Lower interest expense Dividend increases totaling 60% in 2004 (current annual rate $1.60/share) Free cash flow of $1.4 billion Note: See presentation appendix for GAAP EPS and cash flow reconciliation

2004 Guidance Weather ComEd CTC Amort. / Depr. Nuclear Outages /Fuel Exelon Way Load Growth Other RNF Interest 2005 Guidance Invisible dataset 0 2.78 2.86 2.81 2.76 2.76 2.81 2.91 2.96 0 Green 2.78 0.11 0.03 0.05 0.05 0.05 0.1 0.05 0.09 3.1 2004A 2005E Interest O&M Expense/ Other ComEd CTC Expected EPS Drivers Amort.& Depr./ PECO CTC Amort. 2005 Adjusted (non-GAAP) Operating EPS Guidance: $2.90 - $3.10 Nuclear Refueling Outages Weather Load Growth Other Revenue Net Fuel Growth Other Risks and Opportunities +/- CTC Reset +/- Weather +/- Economy +/- Natural Gas Prices Note: See presentation appendix for GAAP EPS reconciliation

1Q05 Financial Summary $0.67 Operating EPS (+9.8% over 1Q04) Higher generation margins Lower interest expense Funded essentially all outstanding pension obligations with $2 billion cash contribution Exited from Generation's investment in Sithe Approximately $820 million of debt deconsolidated from balance sheet Note: See presentation appendix for GAAP EPS reconciliation

Illinois Post-2006 Update - Competition Benefiting IL Customers Since the onset of customer choice in 1997, more than 70% of ComEd's biggest customers have chosen alternatives to bundled rates, some saving up to 15% Residential customers saved 20% with a rate reduction, and even more considering a 10-year rate freeze when the CPI increased 20% (current rates lowest since early 1990's) Since 1998, outage frequency is down 44%, duration is down 53% Nuclear capacity factors have increased from 49% to 93% 9,000 megawatts of new competitive power supply brought on line (and not in rate base)

Illinois Post-2006 Update - Process Moving Forward 12/3/04 ICC staff report to General Assembly endorsed an auction process similar to New Jersey's (best fit with consensus of Procurement Working Group) ComEd made filings at the ICC on February 25 proposing an auction process Details of the filing and case schedule were previewed with all stakeholders including ICC staff Proceeding will likely run through January 2006 Auction has support of a variety of stakeholders Bi-partisan House Committee formed to oversee Post-2006 process (Chairman: George Scully) Hearing testimony from a broad range of stakeholders before determining General Assembly's level of involvement and direction to the ICC A separate filing for delivery rates and new rate design will be made in the 2nd or 3rd quarter of 2005

Understanding the Auction: Product Laddering ComEd Suggested Load Auctioned by Term 50% Auction Load Cap allows ExGen to sell slightly less than 50% of its economic generation directly to ComEd; remainder sold through other channels Annual auctions allow for rebalancing position up to the load cap curve Physical asset ownership not required to participate or win in Load Auctions Notes: Unique product term required in 1st Auction to stagger load in future Auctions 1st Auction term begins 1/1/07 with 5 months added to each term to align with the PJM planning year (June 1 - May 31) 25

ComEd Bundled Tariff for Mass Market 2000 2004 2007 Distr 22 23 26 Trans 2 3 3 Line Losses 4 4 4 Energy/Other 49 47 45 10 77 77 Assumes increase in wires charges to recover increased investment in transmission and distribution infrastructure and costs. Notes: 2000 and 2004 are representative of unbundling existing tariff. Energy/other includes the cost of energy, capacity, load following, weather, switching and congestion. Mass Market represents residential and small commercial and industrial customer classes (<1 MW). ATC range from $32 to $37 (current forward price = $37); adders from 40% to 50% 78 - 88 ~ 13% rate increase Sales mix: more higher rate sales 49 47 45 - 55

Fourth annual reverse auction in NJ completed 2/16/05 While the wholesale price of energy increased by 18% over last year's prices, the staggered terms of the auction contracts will result in customers of NJ's largest utility (PSE&G) seeing an annual increase to total bills of 2.8% Only 1/3 of the energy component in the overall bill is put out to bid annually The energy component is approximately half of the overall bill (with the delivery and transmission components comprising the remaining half) Therefore, in any given year, 1/3 of about 50% (or about 1/6) of the total electric bill is out for bid 25 suppliers participated in the reverse auction with 7 winning bidders BGS Auction Summary

Key Transaction Terms Offer Price: 1.225 shares of Exelon per PSEG share Ownership: 68% Exelon shareholders 32% PSEG shareholders Governance: John W. Rowe to be CEO E. James Ferland to be non-executive Chairman 18 Board members - 12 nominated by Exelon - 6 nominated by PSEG Timing: Expected to close within 12-16 months from 12/20/04 announcement Nuclear Agreement: Operating Services Contract started 1/05 Approvals: Shareholders, Federal and State Regulatory

A "Win-Win"Combination Combined Company Enhanced earnings Regulatory and market diversity Increased operating flexibility Strong, stable cash flow with commitment to solid investment grade ratings Experienced management team PSEG Brings Excellence in transmission and distribution operations Expertise in BGS auction development and participation Strong gas LDC experience Exelon Brings Premier nuclear operation expertise Broad platform for earnings and cash flow growth Large merger integration success

Exelon has proven track record of improving and sustaining safety, operating and cost performance Significant opportunity to improve PSEG fleet performance under Nuclear Operating Services Contract, started January 2005 Every 1% increase in capacity factor for PSEG's nuclear fleet generates pre-tax income of about $12 million Opportunity for Improved Nuclear Performance Exelon Non-Fuel Production Cost ($/MWh) PSEG Non-Fuel Production Cost ($/MWh) Exelon-operated Capacity Factor PSEG-operated Capacity Factor

Premier U.S. Utility Company Generation PEG: EXC: Three urban utilities, with a low-cost, low-emissions generation fleet, in an integrated Regional Transmission Organization (MWs) Exelon PSEG EE&G U.S. Rank Nuclear 16,751 3,484 20,235 1 TOTAL MWs (1) 34,457 17,018 51,475 1 Elec. Customers 5,200,000 2,100,000 7,300,000 1 Gas Customers 460,000 1,700,000 2,160,000 7 (1) Year-end 2004; Generation numbers include long-term contracts. Note: EE&G MWs do not include effect of any market power mitigation.

Market Power Mitigation 2/4/05 - Filed the merger application with FERC 5/9/05 - Filed answer to intervener motions with FERC Proposed Divestiture (5/9/05 filing) "Virtual Divestiture" Transfer control of 2,600MW of baseload nuclear energy (no change from 2/4 filing) Divest a total of 4,000MW fossil fuel facilities (2,900 MW in 2/4 filing) Peaking: 1,200MW (1,000 MW in 2/4 filing) Mid-Merit: 2,800MW (1,900 MW in 2/4 filing) at least 700MW coal-fired (550 MW in 2/4 filing) Exelon Baseload Load Following Peaking PSEG Baseload Load Following Peaking

Opportunity for Improved T&D Reliability 2003 Key Performance Indicators Exelon Exelon PSE&G PSE&G Performance Quartile Performance Quartile Reliability - Outage Frequency (SAIFI) 1.09 2nd 0.63 1st Customer Satisfaction (ACSI) 70 4th 76 2nd Safety (OSHA Recordables Rate) 2.40 2nd 2.88 2nd Total T&D $/Customer $235 3rd $191 1st PSE&G has proven track record for reliable, cost effective T&D operations Exelon reliability has improved -- committed to further improvements Focus on customer satisfaction

$500 Million of Synergies in Year 2 Corporate/BSC 0.39 T&D 0.11 GENCO Corp 0.07 Trading 0.09 Nuclear 0.34 7% 9% 34% 39% 11% Trading Genco Corp/ Fossil T&D Corporate, Business Services Nuclear (1) Staffing 0.43 Nuclear Production Improvements 0.14 Nuclear Outages 0.03 IT 0.09 Corp Programs 0.15 Supply 0.16 15% 16% 43% 9% Corporate Programs Info Technology Staffing Supply By Business By Category Nuclear Production Improvements 14% 3% Nuclear Outage Costs (1) Includes cost and production improvement

Solid Balance Sheet Exelon and PSEG believe they will retain solid investment-grade ratings on a combined basis Pro Forma Key Ratios (1) Year 1 Year 2 Funds from Operations / Average Total Debt 28% 31% Funds from Operations Interest Coverage 5.8x 6.2x EBITDA Interest Coverage 7.0x 7.1x Debt / Capital 41% 41% (1) Ratios exclude securitized debt and PSEG Energy Holdings

EE&G Value Proposition Solid Delivery Business Stable growth Improving operations Constructive regulatory processes in IL, NJ and PA Geographic diversity Exceptional Generation Business Large, low cost, low emissions generation fleet in competitive markets with strengthening wholesale prices Fuel, dispatch and locational diversity Strong operating performance and results-oriented culture Experienced power marketing/risk management team Experienced management team Strong balance sheet and financial discipline History of delivering on commitments

Anticipated Timeline - Update Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Announce Transaction 12/20/04 Exelon & PSEG Shareholder Meetings FERC, NJBPU, ICC Regulatory Filings 2/4/05 File Joint Proxy Statement 2/10/05 Work to Secure Regulatory Approvals (FERC, SEC, NRC, DOJ, NJBPU, NJDEP*, PAPUC, ICC*, NYPSC and others) Develop Transition Implementation Plans Receive Regulatory Approvals Close Transaction Implement Nuclear Operating Services Agreement 1/17/05 Q2 2006 * Notice filing only

Illinois Procurement Filing Overview Annual "reverse auction" to procure supply for customers post 2006 Staggered 1, 3 and 5 year contracts for <1 MW customers Staggering creates rate stability for customers 100% of load bid out in year 1; 40% each year thereafter Recent New Jersey BGS auction resulted in wholesale price increase of 18% over prior year due to higher fuel prices, but staggering process reduced impact on customers' electric bills to a 2.8% increase NJ ratepayer advocate: "We don't like any increases, but considering what is going on in the market, it is not bad. We were expecting worse." Large customers to be offered annual or hourly price -- depending on whether or not they are subject to competitive declaration 50% load cap for any single supplier Requires mark-to-market collateral posting by suppliers Tariff translates wholesale auction into retail rates by customer class Auction managed by an independent third party and overseen by ICC

ComEd Delivery Service Investments (Pro forma $ in Millions) 2000 2004Chg. Gross DST Plant $ 8,518 $ 11,300 33% LESS: Accumulated (3,747) (4,760) 27% Depreciation PLUS: Other Addt's (CWIP, (325) 60-- Mtrls, Oper. Reserves, OPEB) LESS: Deferred Taxes (829) (1,190) 44% Rate Base $ 3,617 $ 5,410 50% Weighted Average Cost of 9.0% 8.7% Capital - 2004 estimated Authorized Return 326 471 Taxes on Interest (57) (56) Synchronization Deduction After Tax Rate Base 269 415 Return Requirement Gross Revenue Conversion 1.67 1.66 Factor Authorized Return Grossed $ 448 $ 688 Up for Taxes Operating Expenses before 1,115 1,280 15% Income Taxes Total Delivery Service 1,563 1,968 26% Revenue Requirement Less: Delivery Service 55 89 62% Revenues Provided by Other Tariffs Revenue Requirement $ 1,508 $ 1,880 25% Provided by Delivery Service Tariff ComEd has made significant investments in Delivery Rate Base and experienced significant increases in costs since the last rate case test year. Note: Financial data is simplified and rounded for illustrative purposes.

ComEd Goodwill Impairment assessment performed at least annually (4th quarter) to determine if estimated fair value (FV) of ComEd supports recorded goodwill Assessment uses discounted cash flow analysis to estimate FV Dependent on variables including interest rates, utility sector market performance, market power prices, post-2006 rate/regulatory structures, operating and cap ex requirements Assessment performed in two steps: Step 1: Compare FV of ComEd to its book value (BV) including goodwill - if FV exceeds BV, no impairment; if not, then go to Step 2 Step 2: Compare FV of goodwill to BV of goodwill - if FV exceeds BV, no impairment; if not, an impairment loss is reported as reduction to goodwill and charged to operating expense Goodwill impairment has no cash flow impact No impairment recorded at ComEd to date, but reasonable possibility goodwill will be impaired going forward Any future impairment charges at ComEd will likely be offset in Exelon's consolidated results Impairment test at Exelon level considers cash flows of entire EED segment, including both ComEd and PECO; PECO has no goodwill and its estimated FV substantially exceeded its BV under the 2004 test Goodwill impairment has no impact on ComEd's ROE rate cap during the transition period through 2006 Impact on ComEd distribution rate case: Goodwill not included in rate base (no return of goodwill) A goodwill impairment would decrease the common equity included in the determination of the overall weighted cost of capital for ratemaking purposes $1.2 billion of accelerated ComEd debt retirements in 2004 ensures ComEd's equity ratio will be sufficient to justify a request for an equity ratio of at least 50% in ComEd's distribution rate case, even assuming a write-off of 50% of existing goodwill

ComEd Balance Sheet/Capital Structure 12/31/03 12/31/03 12/31/04 12/31/04 Illustrative 12/31/05(1) Illustrative 12/31/05(1) $ in Billions % of Total Cap. $ in Billions % of Total Cap. $ in Billions % of Total Cap. Goodwill 4.7 - 4.7 - 2.4 - Debt 6.4 50% 4.9 42% 4.6 51% Common Equity 6.3 50% 6.7 58% 4.4 49% Debt(2) 4.8 43%(2) 3.5 34%(2) 3.5 44%(2) Common Equity 6.3 57%(2) 6.7 66%(2) 4.4 56%(2) (1) Assumes a scenario where one-half of goodwill is written off and $0.3B securitization debt matures in 2005. Equity does not include the impacts of any capital contributions, dividends or net income for 2005. (2) Excludes securitization debt from total debt and total capitalization

Break-Even Price for New Construction Energy/ Capacity $/MWh POLR Price $/MWh Variable Costs Fixed Costs 0 13 26 40 53 66 79 92 2,230 Net MWe 93% Capacity Factor ~$1,250 / kWe $7.15/MWh Fuel ~3 years to Permit ~4 years to Construct Tech. Readiness: Low 670 Net MWe 85% Capacity Factor ~$1,550 / kWe $1.20/MMBTU Fuel ~2 years to Permit ~3 years to Construct Tech. Readiness: High 810 Net MWe 85% Capacity Factor ~$1,800 kWe $1.20/MMBTU Fuel ~2 years to Permit ~3 years to Construct Tech. Readiness: Med. 500 Net MWe 90% Capacity Factor ~$600/ kWe $5.10/MMBTU Fuel ~1.5 years to Permit ~2 years to Construct Tech. Readiness: High Global Assumptions: 40-year plant life; 9% after-tax weighted avg. cost of capital; 40% tax rate; 3% cost, fuel and power price escalation. Fixed costs include fixed O&M, capital and return on capital. Variable costs include variable O&M, fuel and emissions costs. POLR price assumed to be 1.32 x energy + capacity (equivalent to 1.5 x energy only) for base-loaded plants. (1) CERA Energy Forecast adjusted for Capacity 2007 Forecast (1) 2005 Market

GAAP EPS Reconciliation 2000-2002 2000 GAAP Reported EPS $ 1.44 Change in common shares (0.53) Extraordinary items (0.04) Cumulative effect of accounting change -- Unicom pre-merger results 0.79 Merger-related costs 0.34 Pro forma merger accounting adjustments (0.07) 2000 Adjusted (non-GAAP) Operating EPS $ 1.93 2001 GAAP Reported EPS $ 2.21 Cumulative effect of adopting SFAS No. 133 (0.02) Employee severance costs 0.05 Litigation reserves 0.01 Net loss on investments 0.01 CTC prepayment (0.01) Wholesale rate settlement (0.01) Settlement of transition bond swap -- 2001 Adjusted (non-GAAP) Operating EPS $ 2.24 2002 GAAP Reported EPS $ 2.22 Cumulative effect of adopting SFAS No. 141 and No. 142 0.35 Gain on sale of investment in AT&T Wireless (0.18) Employee severance costs 0.02 2002 Adjusted (non-GAAP) Operating EPS $ 2.41

GAAP EPS Reconciliation 2003-2004 2003 GAAP Reported EPS $ 1.38 Boston Generating impairment 0.87 Charges associated with investment in Sithe Energies, Inc. 0.27 Severance 0.24 Cumulative effect of adopting SFAS No. 143 (0.17) Property tax accrual reductions (0.07) Enterprises’ Services goodwill impairment 0.03 Enterprises’ impairments due to anticipated sale 0.03 March 3 ComEd Settlement Agreement 0.03 2003 Adjusted (non-GAAP) Operating EPS $ 2.61 2004 GAAP Reported EPS $ 2.78 Charges associated with debt repurchases 0.12 Investments in synthetic fuel-producing facilities (0.10) Severance 0.07 Cumulative effect of adopting FIN No. 46-R (0.05) Settlement associated with the storage of spent nuclear fuel (0.04) Boston Generating 2004 impact (0.03) Charges associated with investment in Sithe Energies, Inc. 0.02 Costs related to proposed merger with PSEG 0.01 2004 Adjusted (non-GAAP) Operating EPS $ 2.78 Reconciliation of GAAP Reported and Adjusted (non-GAAP) Operating Earnings per Diluted Share

GAAP EPS Reconciliation 1Q05/1Q04 1Q04 GAAP Reported EPS $ 0.62 Cumulative effect of adopting FIN No. 46-R (0.05) Boston Generating, LLC 2004 impact 0.03 Mark-to Market 0.03 Investments in synthetic fuel-producing facilities (0.02) 1Q04 Adjusted (non-GAAP) Operating EPS $ 0.61 1Q05 GAAP Reported EPS $ 0.77 Mark-to Market (0.06) Investments in synthetic fuel-producing facilities (0.02) Sithe Energies, Inc. 2005 impact (0.02) 1Q05 Adjusted (non-GAAP) Operating EPS $ 0.67 Reconciliation of GAAP Reported and Adjusted (non-GAAP) Operating Earnings per Diluted Share

Full Year 2004 Cash Reconciliation Total Increase in Cash and Cash Equivalents to Free Cash Flow Reconciliation ($ in millions) GAAP Increase in Cash and Cash Equivalents $ 35 Adjustments for Goal: Discretionary Debt Activity: - Change in Short-Term Debt (164) - Net Long-Term Debt Retirements(1) 1,424 - Other Financing Activities (34) Cash from Long-Term Incentive Plan(2) (158) Other Discretionary Adjustments(3) 283 Total Adjustments 1,351 Free Cash Flow $ 1,386 (1) Includes net long-term debt issuances and payment on the acquisition note to Sithe Energies, and excludes ComEd Transitional Funding Trust and PECO Energy Transition Trust Retirements (2) Net of treasury shares purchased. (3) Includes the incremental increase in dividend payments over 2003, exclusion of Sithe cash, severance payments, call premiums associated with the redemption of debt as a result of the accelerated liability management plan, and the tax effect of discretionary items.

2005 Earnings Guidance Exelon's adjusted (non-GAAP) operating earnings for 2005 are expected to be in the range of $2.90 to $3.10 per share. Exelon's outlook for adjusted (non-GAAP) operating earnings excludes income resulting from investments in synthetic fuel-producing facilities, the financial impact of the company's investment in Sithe and merger-related costs. Giving consideration to these factors, Exelon estimates 2005 GAAP earnings will fall in the range of $2.95 to $3.15 per share. This estimate does not include any impact of future changes to GAAP.

Cash Flow Definitions We define free cash flow as: Cash from operations (which includes pension contributions and the benefit of synthetic fuel investments), less Cash used in investing activities, less Transition debt maturities Common stock dividend payments at 2003 rates Other routine activities (e.g., severance payments, tax effect of discretionary items, etc.) We define available cash flow as: Cash from operations less capital expenditures, less common stock dividend payments, less securitized debt retired