Exhibit 99

Edison Electric Institute Financial Conference Hollywood, Florida November 6-9, 2005 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 (1) the Exelon Companies' 2004 Annual Report on Form 10-K in (a) ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Business Outlook and the Challenges in Managing the Business for each of Exelon, ComEd, PECO and Generation and (b) ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 20, ComEd- Note 15, PECO-Note 14 and Generation-Note 16 and (2) Exelon's Current Report on Form 8-K filed on May 13, 2005 in (a) Exhibit 99.2 Management's Discussion and Analysis of Financial Condition and Results of Operations - Exelon - Business Outlook and the Challenges in Managing the Business and (b) Exhibit 99.3 Financial Statements and Supplementary Data - Exelon Corporation and (3) other factors discussed in filings with the Securities and Exchange Commission (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' Quarterly Report on Form 10-Q for the period ended September 30, 2005, in (a) Forward Looking Statements and (b) ITEM 2. 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 Exelon Corporation PSEG Overview 2005 Performance 2006 Outlook & Environment Merger Update Exelon Overview 2005 Performance 2006 Outlook & Environment Illinois Update

PSEG Overview - 2005 Electric Customers: 2.1M Gas Customers: 1.7M ~40% of Operating Earnings Nuclear Capacity: 3,484 MW Total Capacity: 14,549 MW ~45% of Operating Earnings ~15% of Operating Earnings Traditional T&D Leveraged Leases Operating Earnings(1): $770M - $810M EPS Guidance: $3.15 - $3.35 Assets (as of 9/30/05): $30B Domestic/Int'l Energy Regional Wholesale Energy (1) Includes the parent impact of $(65-75)M; Excludes Merger-related costs

9/30/04 YTD Continuing Operations EPS Power PSE&G Energy Holdings Other 9/30/05 YTD Operating EPS West 720 715 715 716 730 0 0 3 0 35 21 725 PSEG YTD 2005 Performance Improved Nuclear & Fossil Operations $0.03 Depreciation $(0.04) Other $(0.01) Weather $0.05 Interest $0.03 O&M $(0.06) Demand & Other $(0.02) $2.79 * $2.78 Texas & South America $0.15 Currency Impacts $0.03 Lease Terminations & Other $0.04 Repatriation $(0.04) Additional Shares $(0.06) Parent Interest $(0.09) $(0.02) $0.00 $0.18 $(0.15) * Excludes $0.11 Merger-related costs

2005 Key Events Natural Gas Price Impact Longer-term Benefits Liquidity Customer Impact Dampened - BGS: 3-year contracts - BGSS: storage and hedges Balance Sheet Liquidity - $2.1B as of 10/28 - $500M of New Facilities Cash - Waterford Sale - Securitization: Year 4 BGS - Repatriation Regulatory Gas Rate Case - $133M increase requested including $55M Depreciation Electric Proceeding - $64M Depreciation Credit Operations Nuclear - 2005 Projected Capacity: 88% vs. 2004: 82% - Salem 2 outage: 36 Days - Salem 1 progressing Fossil - 10% more MWh's YTD than last year - BEC & Lawrenceburg Operational - 21% improvement in Coal Capacity Factor

Attractive Pricing Environment PJM Western Hub (RTC) Forward Prices and NYMEX Natural Gas (Henry Hub) BGS Prices (NJ Avg -Approx) $32 - $33 $36 - $37 $44 - $46 PJM West RTC NYMEX (Henry Hub) $53 $55 $66 $5.15 - $5.35 $5.25 - $5.40 $6.50 - $6.65 RTC = round the clock

BGS and Long-Term Contracts 0% 20% 40% 60% 80% 100% Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 % of Nuclear and Coal Generation Generation output not under contract Other term energy contracts 2003 BGS United Illuminating 2004 BGS 2005 BGS PSEG Power Term Contracts 85 - 90% 65 - 75% 35 - 50% % Hedged:

2005 Guidance Energy Prices Unit Operations Regulatory Filings Depreciation & Interest O&M Other 2006 Guidance 2007 2008 West 755 755 818 846 821 801 788 0 0 0 0 63 28 8 33 20 13 788 828 869.9 Meaningfully Above 2005-2006 Rates Gas Base Rate Case New Assets New Assets Sales Driven by Commodity Prices and Contracts Rolling Off Weather NDT Depreciation Credit Inflation $3.15 $3.35 to $3.45 $3.75 to PSEG Stand-Alone 2006 Earnings Guidance NDT = nuclear decommissioning trust

2006 Assumptions and Sensitivities Assumption Change Per Share Impact Natural Gas Prices (NYMEX) $10/mmbtu $1/mmbtu $0.01 RTC Energy - PJM West $69/MWh $5/MWh $0.05 Nuclear Capacity Factor 91.4% 1% $0.04 PJM Capacity Prices $3/kW-yr $5/kW-yr $0.05

Merger Update Generation PEG: EXC:

Market Concentration Mitigation 7/1/05 - FERC issued merger approval order Working with DOJ and NJ BPU 4,000MW Fossil Divestiture Must complete within 12 months of merger closing Peaking: 1,200MW High Mid Merit: 900MW CCGT: 1,200MW Coal: 700MW Merrill Lynch advising on sale 2,600MW Nuclear Virtual Divestiture MDI selected as auction manager LD product sold as "Eastern Nuclear Generation Aggregate (ENGA)" 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

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 bill do not apply DOJ Hart-Scott-Rodino review The waiting period expired September 1 DOJ review continues, but is not expected to delay closing Pennsylvania PECO announced settlement with major parties on 9/13/05, subject to approval Final decision expected in December or January New Jersey Schedule revised; hearings now planned for January Final BPU decision expected in May, unless we settle earlier SEC PUHCA repeal will be effective Feb. 8 No PUHCA order needed unless we close before then

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

Exelon Update

Exelon Overview - 2005 (1) Includes long-term contracts Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP 2005E Operating Earnings: $2.0-$2.1B EPS Guidance: $3.00-$3.15 Assets (9/30/05): $43B Pennsylvania Utility Illinois Utility Nuclear Generation Fossil Generation Power Marketing Nuclear Capacity: 16,900 MW Total Capacity: 33,700 MW(1) ~50% of Operating Earnings Electric Customers: 5.2M Gas Customers: 0.5M ~50% of Operating Earnings Traditional T&D Regional Wholesale Energy

9/30/04 YTD Operating EPS Generation Margins Weather Other 9/30/05 YTD Operating EPS West 720 720 740 730 0 0 20 25 19 725 Higher margins on market sales $0.36 Higher costs to serve affiliate load $(0.20) $2.37 $2.17 Higher delivery volumes Asbestos reserve $(0.04) O&M $(0.03) Depreciation & amortization $(0.03) Share dilution $(0.03) Enterprises & all Other $(0.02) $0.16 $0.19 $(0.15) Exelon YTD 2005 Performance Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP 9% growth in operating EPS YTD

2004A 2005 Estimate 2006 Estimate 2007 East 2.78 3 3 0.125 0.24 $2.78 $3.00-$3.15 $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 Original 2005 Guidance: $2.85 - $3.05 Strong earnings growth will continue in 2006 and accelerate in 2007 Adjusted (non-GAAP) operating EPS Guidance

Exelon consolidated: FFO / Interest 7.5x BBB/Baa2/BBB+ FFO / Debt 39% Debt Ratio 48% Generation: FFO / Interest 13.6x BBB+/Baa1/BBB+ FFO / Debt 87% Debt Ratio 29% ComEd: FFO / Interest 5.7x A-/A3/A- FFO / Debt 27% Debt Ratio 41%(2) PECO: FFO / Interest 12.6x A-/A2/A FFO / Debt 36% Debt Ratio 45% 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) Assumes half of ComEd goodwill is written off Exelon's Balance Sheet is strong Credit Ratings(1) S&P/ Moody's/ Fitch Projected 2005 Key Credit Measures

ComEd becomes a pure wires business - Returns determined through traditional regulatory processes - No generation margin - 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

2002 2003 2004 2005E 2006E 2007* Generation 0.24 0.3 0.33 0.5 0.51 0.7 ComEd 0.47 0.45 0.42 0.26 0.27 0.14 PECO 0.29 0.25 0.25 0.24 0.22 0.16 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 Earnings * Based on Thomson First Call consensus EPS estimate of $4.20

Illinois Update

1997 Illinois Restructuring Act The Illinois Restructuring Act has benefited both customers and shareholders Consumers have benefited: Since 1997, ComEd residential electric rates have been reduced 20% and frozen through the end of 2006 As a result, residential customers will have enjoyed $4 billion in savings during this period Competition has developed: More than 50% of large customer load >1 MW served by retail energy suppliers 23.5% of ComEd's total load served by retail energy suppliers 18 suppliers certified by the Illinois Commerce Commission Eight suppliers serving 20,000 GWh load Exelon has restructured: As a result of the 1997 Act, the company was separated into two businesses We have used the restructuring and transition period to improve both delivery and generation businesses Invested $3 billion in T&D infrastructure over past 5 years for improved reliability Nuclear capacity factor has risen to 93+% and nuclear production costs are down from $26.80 per MWh at ComEd in 1997 to $12.43 per MWh fleet wide in 2004

Moving Illinois Forward Summer 2004 - ICC Stakeholder Workshops Consensus develops around the use of a competitive procurement process for establishing market-based rates post 2006 ICC staff report recommends a reverse auction (like New Jersey's) as the best available competitive procurement process February 2005 - ComEd files Procurement Case Auction patterned after successful process in NJ and will result in a reliable power supply at the lowest-available market price Hearings were recently completed and a final ICC order is due in January 2006 August 2005 - ComEd files Delivery Case Traditional rate case to recover prudently incurred costs to provide delivery service A final ICC order is due in July 2006 Process is well underway to determine post-transition rates

Actions Underway Regulatory Trying to keep the ICC process on track Seeking FERC determination through Section 205 filing that affiliate contracts won through a reverse auction process will meet Edgar Standards and will be approved Legal Intervening in Attorney General's court case Recently appointed ICC Chairman, who was former Executive Director of CUB, not confirmed by full Senate so ComEd recusal motion is moot Legislative Working to prevent adverse legislation Media and other outreach CORE Ad campaign Business community support Ring fencing ComEd Pursuing appropriate financial, legal and governance actions Working with major stakeholders to reach a reasonable resolution

In Summary Continued strong financial performance at both PSEG and ComEd Merger approvals and integration efforts on track Combined company well positioned for future earnings growth Expect to resolve Illinois issues to the benefit of both our customers and shareholders

Appendix

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

2005 BGS Auction Results 2003 Auction 2004 Auction 2005 Auction East 32.1 36.9 45.14 West 20.6 17.55 20.77 $32 - $33 $36 -$37 $52.70 (10 Month NJ Avg.) $54.45 (12 Month NJ Avg.) $65.91 (36 Month NJ Avg.) $44 -$46 Transmission Ancillary services Load shape Congestion Risk premium Capacity ~ $20 ~ $18 ~ $21 RTC Forward Energy Cost RTC = round the clock

Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Announce Transaction 12/20/04 Shareholder Approvals 7/05 FERC, NJBPU, ICC Regulatory Filings 2/4/05 File Joint Proxy Statement 2/10/05 Work to Secure Regulatory Approvals (FERC, DOJ, ICC*, PAPUC, NJBPU, SEC, and others) Develop Transition Implementation Plans CLOSE TRANSACTION Beginning 1/17/05, Implement Nuclear Operating Services Agreement Q2 2006 * Notice filing only FERC Approval Order 7/1/05 Respond to DOJ 2nd Request Settlement with PA PUC Filed 9/13/05 NJ BPU Hearings Scheduled NJ BPU Final Decision Expected, unless Settled Earlier PA PUC Final Decision Expected Anticipated Merger Timeline NJ Settlement Discussions

Marginal Revenue and Cost per MWh of Retail Load in 3Q 05 ExGen ComEd ExGen PECO 40 21 45 32 -78 14 -140 24 40 45 -40 -45 $/MWh Genco/ ComEd PPA Cost to serve incremental weather-driven load in the spot market in 3Q Genco ComEd PECO Illustration Using Approximate 3Q 05 Data Genco Generation serves both ComEd's and PECO's load at fixed, below-market rates Genco/ PECO PPA Illustration Using Approximate 3Q 05 Data $75 $101 Gen* CTC T&D Gen* CTC T&D * Excludes line losses, ancillaries and gross receipts taxes Cost to serve incremental switching load in the spot market in 3Q ($78) ($140)

Higher Sales to ComEd $/MWh ComEd Genco Exelon Weather Revenue 75 40 75 Cost* (40) (78) (78) Margin 35 (38) (3) Switching Revenue 40 40 40 Cost* (40) (61) (61) Margin -- (21) (21) Warm summer weather was favorable for Delivery but unfavorable for Generation and Exelon overall Higher customer retention was neutral for Delivery and unfavorable for Generation and Exelon Overall Illustration Using Approximate 3Q 05 Data: Higher Sales to PECO $/MWh PECO Genco Exelon Weather Revenue 101 45 101 Cost* (45) (140) (140) Margin 56 (95) (39) Switching Revenue 45 45 45 Cost* (45) (91) (91) Margin -- (46) (46) Profit Impact of Higher Sales at ComEd and PECO in 3Q 05 * Cost to serve incremental load in spot market

Consolidated - Key Assumptions Source: 8/5/05 Exelon Investor Conference

Portfolio Sensitivities for Genco * ATC = Around the Clock Gas Price Sensitivity 1 ($ million pre-tax) Gas +20% Gas -20% Sep to Dec 2005 $7 ($2) Calendar 2006 $56 ($46) Power Price Sensitivity 2 ($ million pre-tax) Power +$1.00 ATC* Power -$1.00 ATC* Sep to Dec 2005 $4 ($3) Calendar 2006 $28 ($27) Notes: 1 Gas prices were changed with a correlated change in power, oil, and coal prices 2 Power prices were changed; fuel prices were held constant Source: 8/5/05 Exelon Investor Conference

Note: Net Cash from Operations includes cash from normal operations, decommissioning investment, and debt issued for pension funding in 2005. See presentation appendix for definition of Free Cash Flow. 3.8 4.0 (0.8) (0.9) (0.5) (0.5) (0.6) (0.6) (1.0) (1.1) (1.1) (1.1) ($5.0) ($4.0) ($3.0) ($2.0) ($1.0) $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 2005E 2006E $ Billions Net Cash from Operations Dividends Transition Debt Retirements EED CapEx Genco CapEx Nuclear Fuel Aug-04 Projected Free Cash Flow Current Projected Free Cash Flow Our current cash flow forecast reflects increased investments in the core business - mainly on the regulated side (0.1) Corp. CapEx Deploying Our Cash Source: 8/5/05 Exelon Investor Conference

Note: Items may not add due to rounding. (in Millions, except EPS) Exelon Consolidated GAAP Earnings to Adjusted (non-GAAP) Operating Earnings - YTD through Sept.

Reconciliation of 2004 GAAP Reported and Adjusted (non-GAAP) Operating Earnings per Diluted Share

2005/2006 Earnings Guidance Exelon's outlook for 2005 adjusted (non-GAAP) operating earnings excludes unrealized mark-to-market adjustments from non-trading activities, income resulting from investments in synthetic fuel- producing facilities, the financial impact of the company's investment in Sithe, certain severance costs, the cumulative effect of the adoption of FIN 47 - "Accounting for Conditional Asset Retirement Obligations," and costs associated with the proposed merger with PSEG. 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 and costs associated with the proposed merger. These estimates do not include any impact of future changes to GAAP. Earnings guidance is based on the assumption of normal weather.

Cash Flow Definition We define free cash flow as: Cash from operations (which includes pension contributions and the benefit of synthetic fuel investments), Cash used in investing activities, Debt issued for pension funding, Cash used for transition debt maturities, Common stock dividend payments, Other routine activities (e.g., severance payments, system integration costs, tax effect of discretionary items, etc.) and cash flows from divested operations

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.