Exhibit 99

Morgan Stanley 13th Annual Global Electricity & Energy Conference New York City March 15-16, 2006 Exelon Corporation Public Service Enterprise Group

Forward-Looking Statements This presentation includes 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 of Exelon Corporation (Exelon), Commonwealth Edison Company, PECO Energy Company, and Exelon Generation Company LLC (collectively, the Exelon Companies) to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (a) the Exelon Companies' 2005 Annual Report on Form 10-K-ITEM 1A. Risk Factors, (b) the Exelon Companies' 2005 Annual Report on Form 10-K-ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 20, ComEd-Note 17, PECO-Note 15 and Generation-Note 17, and (c) other factors discussed in filings with the SEC by the Exelon Companies. The factors that could cause actual results of Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Holdings L.L.C. (collectively, the PSEG Companies) to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) the PSEG Companies' 2005 Annual Report on Form 10-K, in (a) Forward Looking Statements (b) ITEM 1A. Risk Factors, and (c) ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and (2) other factors discussed in filings with the SEC by the PSEG Companies. A discussion of risks associated with the proposed merger of Exelon and PSEG is included in the joint proxy statement/prospectus that Exelon filed with the SEC pursuant to Rule 424(b)(3) on June 3, 2005 (Registration No. 333-122704). 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 Exelon Companies or the PSEG Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

Agenda Tom O'Flynn Executive VP and CFO Public Service Enterprise Group John Young Executive VP, Finance and Markets, and CFO Exelon Corporation Key Messages PSEG Overview 2005 Performance 2006 Outlook & Environment Exelon Overview 2005 Performance 2006 Outlook & Environment EEG Merger Overview

Continued strong stand-alone performance at both Exelon and PSEG Value-added, operationally-driven merger Progressing towards close in second or third quarter 2006 Uniquely positioned generation business Large, low-cost, low-emissions, exceptionally well-run nuclear fleet Upside from end of below-market contracts in Illinois and Pennsylvania and re-pricing of forward market sales Improving power market fundamentals Stable growth delivery businesses with improving operations in three major metropolitan areas Strong balance sheet and financial discipline Experienced management team Key Messages

PSEG Overview

PSEG Overview Electric Customers: 2.1M Gas Customers: 1.7M Nuclear Capacity: 3,494 MW Total Capacity: 13,846 MW Traditional T&D Leveraged Leases 2006E Operating Earnings(1)(2): $875M - $950M 2006 EPS Guidance:(2) $3.45 - $3.75 Assets (as of 12/31/05): $ 29.8B Domestic/Int'l Energy Regional Wholesale Energy (1) Includes the parent impact of $(70-80)M; (2) Excludes Merger-related costs for 2006 and 2005 merger-related costs of $3M for PSE&G and $12M for PSEG Power that are included in Income from Continuing Operations. 2005 Results: $347 M(2) $418 M(2) $196 M 2006 Range: $315M - $335M(2) $475M - $525M(2) $155M - $175M

2005 Results: $3.65* Operating Earnings Sustainable Growth... Improved nuclear operations at Power Favorable markets, particularly in 4th Quarter Combined to provide 38 cent improvement at Power over 2004 * Excludes merger-related costs of 14 cents Favorable Events... Sale of Seminole lease (Resources) - 18 cents Favorable summer weather (PSE&G) - 6 cents NDT rebalancing (Power) - 10 cents Continued Strengthening of Balance Sheet... Additional shares outstanding - 10 cents

Nuclear Operating Services Agreement 2005 Accomplishments Effective January 17, 2005, 3-unit New Jersey site managed by Exelon Successfully restructured and restaffed organization World record for outage with head replacement at Salem 1 Improvements in SCWE - continue ongoing reviews Rigorous cost controls implemented 2004 2005 Salem 1 7401 9431 Salem 2 8745 8876 Hope Creek 5997 7657 77% Capacity Factor 89% Capacity Factor +17% GWhrs PSEG Operated Nuclear Units Actual Output 2004-2005

2005 Actual Markets Operations New Assets Leases Other 2006 Guidance 2007 2008 West 890 890 1049 1010 966 914 0 0 0 Seminole 159 48 87 33 17 918 1000 1100 NDT 35 Weather Driven by Power Recontracting at Higher Commodity Prices $3.45 to $3.75** $3.65* PSEG Stand-Alone 2006 Earnings Guidance More than 10% Growth Each Year 244M Avg. Shares 253M Avg. Shares NDT Normal Weather *Excludes 14 cents per share of merger costs that are included in Income from Continuing Operations ** Excluding merger costs that are included in Income from Continuing Operations NDT = nuclear decommissioning trust

NYMEX Natural Gas PJM West RTC Henry Hub $/MBTU PJM West RTC $/Mwh PJM Pricing Environment Electricity and Natural Gas Forward Price Movements 2004 - 2008

BGS Auction Results Transmission Ancillary services Load shape Congestion Risk premium Capacity RTC Forward Energy Cost RTC = round the clock Full Requirements 2003 Auction 2004 Auction 2005 Auction 2006 Auction East 34 37 45.14 67.7 West 21.59 18.05 20.77 34.51 $33 - $34 $36 - $37 $55.59 (34 Month NJ Avg.) $55.05 (36 Month NJ Avg.) $65.91 (36 Month NJ Avg.) $44 - $46 ~ $21 ~ $18 ~ $21 $102.21 (36 Month NJ Avg.) $67 - $70 ~ $32 Increase in Full Requirements Component Due to: Increased Congestion (East/West Basis) Anticipated Increase in Capacity Markets/RPM Higher Volatility in Market Increases Risk Premium

Significant Forward Hedging of Nuclear and Coal > 95% 85 - 95% 65 - 80% 2006 2007 2008 % Hedged

PSE&G Regulatory Filings Excess Depreciation Credit $64M annual credit expired December 31, 2005 BPU Order Issued February 7, 2006 PSE&G to file 1Q 2006 actual results by June 15, 2006 $5M monthly impact on earnings and cash flow Gas Base Rate Case Current rates in effect since January 2002 $133 M revenue increase requested - Effective October 1, 2006 3.78% Overall Increase Requested ROE 11% Depreciation Increase of $55M February 28 - updated test year data with 12 months of actual results filed with BPU

Energy Holdings Provides Strong Cash Flow Executing strategy of opportunistically monetizing assets at PSEG Global $900M of Cash Distributions to PSEG in 2004 & 2005 $240M Repatriated in 2005 Under JOBS Act Net Proceeds from 2004 & 2005 Asset Sales Exceeded $700M Debt Reduction of more than $600M in two years Redeemed $300M of debt in 2004 Called entire 2007 maturity of $309M in late 2005 $300M proceeds from sale of Polish assets expected in 2Q '06 Leveraged Leases Int'l Distribution Int'l Generation Domestic Generation Other* Energy Holdings 0.39 0.26 0.07 0.12 0.16 Assets of $7.1B at 12/31/05 * Primarily Polish Assets reported as Discontinued Operations Improved stability of Earnings and Cash Flow Selected upside, particularly in Texas

Improving Financial Strength Third Consecutive Annual Increase in PSEG Dividend 2006 indicated Annual Dividend is $2.28 Meeting Liquidity Demands $3.7B of Credit Facilities at Year-End, $2.9B for PSEG/Power Collateral postings of $1.2B at 12/05 reduced by 50% as of mid- February PSEG Remains Committed to Improving its Credit Profile PSEG and Power anticipate meaningful improvements in credit measures Favorable market conditions and improved operations provide strong cash flows PSE&G continues to provide stable and predictable performance Energy Holdings maintains FFO coverage targets Asset sale proceeds to balance needs of shareholders and bondholders

Exelon Overview

Exelon Overview (1) At 12/31/05; includes long-term contracts and investments in two facilities in Mexico of 230 MWs Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP Pennsylvania Utility Illinois Utility Nuclear Generation Fossil Generation Power Marketing Nuclear Capacity: 16,856 MW Total Capacity: 33,520 MW(1) ~50% of Operating Earnings Customers Electric: 3.7M 1.5M Gas: - 0.5M ComEd & PECO each contribute ~25% of Operating Earnings Traditional T&D Regional Wholesale Energy 2006E Operating Earnings: $2.0-$2.2B 2006 EPS Guidance: $3.00-$3.30 Assets (12/31/05): $42.4B

Looking Back: 2000 - 2005 Exelon had 9.9% average annual operating earnings per share growth driven by: PECO / Unicom merger Improved operations Core growth in retail delivery volumes Effective commodity risk management Cost management initiatives Debt reduction and refinancings Despite: Retail rate freeze Merchant power overbuild Volatile wholesale prices Note: See presentation appendix for GAAP EPS reconciliation

2004A 2005A 2006 Estimate 2007 East 2.78 3.09 3 0.24 $2.78 $3.10 $3.00-$3.30 + Generation Margins + Weather + Load Growth - Other Exelon's EPS Drivers: 2004 - 2007 + Generation Margins + Load Growth - Weather - Higher O&M + End of Illinois Transition Period + PECO Generation Rate + Load Growth - Inflation Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP 2005 Guidance: $3.00 - $3.15 Strong earnings growth will continue in 2006 and accelerate in 2007 Adjusted (non-GAAP) operating EPS Guidance

2006E 2007E 2008E 2009E 2010E 2011E PECO 40000 40000 40000 40000 40000 0 ComEd 80000 0 0 0 0 0 Market 80000 135000 135000 135000 135000 175000 Market sales PECO fixed price contract ~$50/MWhr ComEd fixed price contract ~$35/MWhr GWhrs Notes: Approximate 25,000 GWhr projected decrease in supply after 2006 reflects a reduction in purchased power. Chart representation for illustrative purposes only. PECO fixed price contract ~$45/MWhr Total Supply including Purchases Generation Market Opportunity Maximum allowable Generation share of ComEd auction (35% load cap)

2002 2003 2004 2005 2006E* 2007E* Generation 0.58 0.78 0.93 1.57 1.67 3.17 ComEd 1.13 1.18 1.16 0.77 0.78 0.5 PECO 0.7 0.65 0.69 0.76 0.7 0.65 A further shift in relative earnings contribution from Energy Delivery to Generation will occur in 2007 when ComEd becomes a pure wires company and Generation gets a market price for its Midwest production Composition of Operating EPS * 2006: represents mid-point of guidance range. 2007: represents Thomson First Call consensus EPS estimate of $4.32 as of 3/10/06 for Exelon stand-alone. Segment results are illustrative only. Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP $2.41 $2.61 $2.78 $3.10 $3.00-$3.30 (Illustrative)

Current ComEd bundled rate Procurement Case Proceedings Distribution Case Proceedings 2/25/05 Procurement case filed Sept. 2006 Initial auction to take place 3/21-3/29/06 Hearings scheduled 6/8/06 ALJ proposed order July 2006 ICC order New rates effective January 1, 2007 Dec. 2004 Post-2006 Final ICC Staff Report supported auction process Rates frozen since 1997 and subsequently reduced 20%. Expected increase with ComEd's mitigation proposal will bring residential rates no higher than 1995 level over 3 years. Legislative Proceedings 1/11/06 Legislative session began 4/7/06 Legislative session scheduled to end Fall 2006 Veto session 1/24/06 ICC votes 5-0 for reverse auction 12/16/05 FERC confirms auction meets its principles Illinois Regulatory/Legislative Timeline 8/31/05 Distribution case filed

EEG Merger Overview

A "Powerful" Combination EEG: 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 BGS = Basic Generation Service LDC = local distribution company

Market Concentration Mitigation 7/1/05 - FERC issued merger approval order Working with DOJ and NJ BPU 4,000 MW Fossil Divestiture Must complete within 12 months of merger closing Peaking: 1,200 MW High Mid Merit: 900 MW CCGT: 1,200 MW Coal: 700 MW Merrill Lynch advising on sale 2,600 MW Nuclear Virtual Divestiture MDI selected as auction manager LD product sold as "Eastern Nuclear Generation Aggregate (ENGA)" PJM Market Monitor 2/9/06 report concluded that proposed 6,600 MW divestiture passes his market concentration screens, that are based on the DOJ merger policy guidelines, for the aggregate energy market Coal Combined Cycle Peaking High Mid Merit Notes: The above map includes all EXC & PEG fossil assets in PJM-East that were included in Appendix J-12 of Dr. William H. Hieronymus' testimony as part of EXC's application under Section 203. Not all of these plants are necessarily under consideration for divestiture as part of the mitigation plan. Some of the sites are multi-unit sites; however, on this map, the entire site may have been classified under a single category. LD product = liquidated damages product

Corporate, Business Services 0.28 Trading 0.13 Fossil 0.1 Nuclear 0.29 Nuclear Production 0.2 20% ~$70m 29% ~$100m 28% ~$100m Trading Genco Corp/ Fossil Corporate, Business Services Nuclear Production Improvements Corp/BSC 0.63 Utility 0.37 43% ~$65m T&D Operations 57% ~$85m Corporate, Business Services 13% ~$45m 10% ~$35m Nuclear Cost Reduction Note: Regulated synergies reflect February 4, 2005 testimony. Unregulated: Exelon Generation Regulated: Exelon Energy Delivery (70% = $350 million) (30% = $150 million) $500 Million of Synergies Beyond Year 1 Synergies are mostly unregulated and backed-up by detailed execution plans Completed substantially all merger integration planning work - prepared to quickly execute

Merger Regulatory Update Status of major filings/approvals: FERC order approving merger without hearing issued 7/1/05 FERC approved the application as proposed with no surprises New merger review provisions in Energy Policy Act of 2005 do not apply Department of Justice Hart-Scott-Rodino review The waiting period expired 9/1/05 DOJ review continues, but is not expected to delay closing Pennsylvania PA Public Utility Commission approved settlement on 1/27/06 New Jersey Schedule revised; hearings expected to conclude around end of March Final NJ Board of Public Utilities' decision expected later; merger close anticipated in the third quarter 2006, unless we settle earlier

Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Announce Transaction 12/20/04 Shareholder Approvals 7/05 FERC, NJBPU, PAPUC, ICC* Regulatory Filings 2/4/05 File Joint Proxy Statement 2/10/05 Work to Secure Regulatory Approvals (FERC, DOJ, ICC*, PA PUC, NJ BPU, and others) Develop Transition Implementation Plans CLOSE TRANSACTION Beginning 1/17/05, Implement Nuclear Operating Services Agreement Q2-Q3 2006 * Notice filing only FERC Approval Order 7/1/05 Respond to DOJ 2nd Request NJ BPU Hearings Scheduled NJ BPU Final Decision Expected PA PUC Settlement Approval 1/27/06 Anticipated Merger Timeline NJ Settlement Discussions NJ Settlement Discussions Scheduled

Unmatched scale and scope through merger Strong balance sheet and financial discipline Stable growth delivery business with improving operations Exceptional generation business uniquely positioned to benefit from: improving power market fundamentals continuing excellence in operations increasing environmental restrictions on fossil fuels Experienced management team EE&G Value Proposition

Morgan Stanley 13th Annual Global Electricity & Energy Conference New York City March 15-16, 2006

Appendix - Additional Information

11,300 MW 5,291 MW 16,591 MW 8,772 MW Midwest Owned Generation: Contracted Gen: Total Generation: ComEd PPA Avg Load: 2,299 MW 2,900 MW 5,199 MW ERCOT/South Owned Generation: Contracted Gen: Total Generation: 10,958 MW 4,414 MW Mid-Atlantic Owned Generation:: PECO PPA Avg Load: 25,099 MW 8,191 MW 33,290 MW Total Owned Generation: Contracted Gen: Total Generation: Generating Plants %MW Nuclear 50 Hydro 5 Coal 9 Intermediate 7 Peaker 29 Exelon Energy Delivery Retail Customers 3.7M Electric in Northern Illinois 1.5M Electric and 0.5M Gas in Southeastern Pennsylvania 542 MW New England Owned Generation: Note: Megawatts based on Exelon Generation's ownership as of 12/31/05; excludes investments in two facilities in Mexico of 230 MWs Exelon is positioned as a multi-regional, baseload producer with merchant activity in the South Our Regional Positions

Expected EPS Drivers Guidance: $3.00 - $3.30 Notes: For reconciliation to GAAP reported EPS, see 4Q 05 earnings release attachments within Exhibit 99 of Form 8-K filed 1/25/06. 2006 Adjusted (non-GAAP) Operating EPS - Stand-alone 2005A Weather Generating RNF Load Growth O&M Outages Amort. / Depr. Interest Expense Other 2006 Budget Invisible dataset 0 2.9755 2.9755 3.3289 3.236732 3.222023 3.192536 3.131035 3.131035 0 Green 3.0999 0.1245 0.353419011 0.092167645 0.186595322 0.010930095 0.029486914 0.061501258 0.018965 3.15 2006 Estimate Weather Generation RNF Interest Expense, Net All Other 2005 Actual Higher generation margins and normal load growth, partially offset by higher O&M costs, will continue to drive earnings growth in 2006 Nuclear Refueling Outages Risks and Opportunities +/- Nuclear Output +/- Weather +/- Power Prices +/- Natural Gas Prices +/- Economy $3.00 - $3.30 Depr./ Amort. Inflation: ($0.10) Pension & Benefits: ($0.05) Option Expense: ($0.04) Load Growth O&M

Exelon Consolidated: FFO / Interest 6.1x BBB 4.5x - 6.5x FFO / Debt 31% 30% - 45% Debt Ratio 51%(3) Generation: FFO / Interest 12.7x BBB+ 5.5x - 7.5x FFO / Debt 92% 40% - 55% Debt Ratio 31% ComEd: FFO / Interest 3.9x A- 3.5x - 4.2x FFO / Debt 18% 20% - 28% Debt Ratio 37%(3) PECO: FFO / Interest 5.8x A- 3.5x - 4.2 x FFO / Debt 23% 20% - 28% Debt Ratio 51% (Stand-alone) Notes: Exelon consolidated, ComEd and PECO metrics exclude securitization debt. See presentation appendix for FFO (Funds from Operations)/Interest and and FFO/Debt reconciliations to GAAP. (1) Senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO; (2) Based on S&P Business Profiles 7, 8 and 4 for Exelon, Generation, and ComEd and PECO, respectively; (3) Reflects $1.2 billion ComEd goodwill write off in 2005 Exelon's Balance Sheet is strong "A" Target Range (2) Projected 2006 Key Credit Measures S&P Credit Ratings(1)

ComEd becomes a pure wires business Returns determined through traditional regulatory processes Received Illinois Commerce Commission (ICC) approval of reverse auction with energy cost pass through - Rate increase expected on delivery services tariff (DST) Exelon Generation gets a market price for all its Midwest production - Approximately 90 TWh nuclear and 10 TWh coal - About 2/3 of which is currently supplied to ComEd at a discount to today's market price Composition of earnings shifts from ComEd to Generation ComEd is willing to work with stakeholders to mitigate the potential customer impacts of transitioning to market prices for generation Net Impact on earnings is expected to be positive for Exelon overall ComEd Genco Exelon Generation Margin - + + DST + N/A + Net Earnings Impact - + + End of Illinois Transition Period

33% of load 33% of load 33% of load 3 yrs. + 5 mos. 3 yrs. 3 yrs. 3 yrs. 2 yrs. + 5 mos. 3 yrs. 3 yrs. 3 yrs. 17 mos. 3 yrs. 3 yrs. 3 yrs. 3 yrs. >> 3 yrs.>> Calendar Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 PJM Planning Year (June 1- May 31) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Transitional contracts shown in black. 17 mos. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. CPP-B CPP-A (for customers < 3 MW) Term Structures for Fixed Price Auctions ComEd Energy Procurement Plan Notes: CPP-A is the auction for the annual fixed price product. It is the default service for customers between 400 KW and 3 MW. CPP-B is the auction for the blended fixed price products (blended 3-year contracts) applicable to residential and small commercial customers below 400 KW.

2004 and 2005 are actual settled prices. Real Time LMP (Locational Marginal Price) Next day market through April 30, LMP from May to Dec Next day over-the-counter market Average NYMEX settle prices 2006 information is a combination of actual prices through March 8, 2006 and market prices for the balance of the year 2007 and 2008 are forward market prices as of March 8, 2006 Source: Prices based on a survey of market observations from multiple electronic and over-the-counter brokers Current Market Prices

Energy/ Capacity $/MWh POLR Price $/MWh Variable Costs Fixed Costs 0 14 27 41 54 68 95 108 1,500 Net MWe 93% Capacity Factor ~$1,580 / kWe $4.00 / MWh Fuel ~3 years to Permit ~5 years to Construct Tech. Readiness: Low 500 Net MWe 85% Capacity Factor ~$2,000 / kWe $2.10 / MMBTU Fuel ~2 years to Permit ~3 years to Construct Tech. Readiness: High 590 Net MWe 79% Capacity Factor ~$2,200 kWe $2.10 / MMBTU Fuel ~2 years to Permit ~4 years to Construct Tech. Readiness: Low 510 Net MWe 90% Capacity Factor ~$700/ kWe $8.00 / MMBTU Fuel ~1.5 years to Permit ~2 years to Construct Tech. Readiness: High Global Assumptions: Costs exclude carbon capture; 40-year plant life; 9% after-tax weighted avg. cost of capital; 40% tax rate; 3% cost escalation. Fixed costs include fixed O&M, capital and return on capital. Variable costs include variable O&M, fuel and emissions costs. Fuel assumptions are IL #6 (coal) and ComEd City Gate (gas). POLR price assumed to be 1.35 x energy + capacity (equivalent to 1.5 x energy only) for base-loaded plants. (1) PJM NiHub forward for Cal 2007 ATC ($46.36/ MWh on 3/08/06). 81 2005 Historical 2007 Forward (1) Break-Even Price for New Construction - 2006$

Targeted capital investment and sound operating fundamentals driving fleet efficiency and reliability Market-driven investments in plant improvements that increase unit profitability Material condition improvement resulting in improved unit reliability, heat rate and capacity Capitalizing on market opportunities through improved operating flexibility and market responsiveness Application of Management Model has resulted in improved operations; will provide similar results in the larger PSEG fossil fleet Exelon Power is well positioned to capitalize on market opportunities Exelon Power Performance - Reliability

Nuclear Performance - Production Sustained nuclear production reliability Continued growth in generation output Consistently high capacity factors Continued excellence in refueling outage performance Exelon Nuclear's sustained reliability is a competitive advantage Data sources: Nucleonics Week, Electric Utility Cost Group. Exelon data excludes Salem

Exelon capitalizes on its nuclear cost advantage Consistent improvement in production cost Industry leader in production cost by a substantial margin The size and scale of the fleet enables low-cost generation Exelon's low-cost nuclear generation is a competitive advantage Data source: Electric Utility Cost Group Nuclear Performance - Cost

2004 2005 2006 2007 2008 2009 2010 Contracted 10700 8991 6923 8456 7342 3629 2520 Flexibilities 1810 3517 1707 1571 186 70 Demand 8437 11587 8472 10027 7528 9196 7393 Uranium market prices have increased, but Exelon is managing its portfolio Reduced uranium consumption by 25% Contracting strategy protects us from increases through 2008 Uranium is a small component of total production cost Expect long-term fundamentals in $20-25 range due to new uranium production Exelon Nuclear is managing fuel costs Nuclear Performance - Fuel Costs

GAAP EPS Reconciliation 2000-2002 $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 $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 $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

$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 $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 GAAP EPS Reconciliation 2003-2005 $1.36 Investments in synthetic fuel-producing facilities (0.10) Charges related to Exelon's anticipated merger with PSEG 0.03 Impairment of ComEd's goodwill 1.78 2005 financial impact of Generation's investment in Sithe (0.03) Cumulative effect of adopting FIN No. 46-R 2005 Adjusted (non-GAAP) Operating EPS 0.06 $3.10

2006 Exelon Earnings Guidance The outlook for 2006 adjusted (non-GAAP) operating earnings is Exelon stand-alone and excludes unrealized mark-to-market adjustments from non-trading activities, income resulting from investments in synthetic fuel-producing facilities, significant impairments of intangible assets, certain severance costs, and costs associated with the proposed merger with PSEG. These estimates do not include any impact of future changes to GAAP. Earnings guidance is based on the assumption of normal weather.

20,000 4,000 8,000 12,000 16,000 2002 2003 2004 2005 2006 2007 2008 1 Year 170 Tranches 10 months 104 Tranches 34 months 51 Tranches 1 Year 50 Tranches 3 Years 51 Tranches 2006 FP Auction Load (projected) 2005 FP Auction Load 50 Tranches 2007 FP Auction Load (projected) Total NJ BGS Load (MW) NJ BGS Auction Structure * Annualized margin to forward curve on date of BGS auction Key Competitive Pressure: BGS Auction Results

FFO Calculation and Ratios

Net Income

Add back non-cash items:

+ Depreciation, amortization (including nucl fuel amortization), AFUDC/Cap Int

+ Change in Deferred Taxes

+ Gain on Sale and Extraordinary Items

+ Trust-Preferred Interest Expense

- Transition Bond Principal Paydown

FFO

FFO Interest Coverage

FFO + Adjusted Interest

Adjusted Interest

Net Interest Expense (Before AFUDC & Cap Interest)

- Trust-Preferred Interest Expense

- Transition Bond Interest Expense

+ 10% of PV of Operating Leases

Adjusted Interest

FFO Debt Coverage

FFO

Adjusted Average Debt (1)

Debt:

LTD

STD

- Transition Bond Principal Balance

Add debt equivalents:

.+ A/R Financing

+ PV of Operating Leases

Adjusted Debt

(1) Use average of prior year and current year adjusted debt balance

Debt to Total Cap

Adjusted Book Debt

Total Adjusted Capitalization

Debt:

LTD

STD

- Transition Bond Principal Balance

Adjusted Book Debt

Capitalization:

Total Shareholders’ Equity

Preferred Securities of Subsidiaries

Adjusted Book Debt Total Adjusted Capitalization

Note: FFO and Debt related to non-recourse debt are excluded from the calculations.