Exhibit 99

Lehman Brothers 2006 CEO Energy/Power Conference New York City September 6, 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, and 2006 Quarterly Reports on Form 10-Q in (a) Forward Looking Statements (b) Risk Factors, and (c) 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 PSEG Update Exelon Update Merger Update

PSEG Update

PSEG Overview Electric Customers: 2.1M Gas Customers: 1.7M Nuclear Capacity: 3,494 MW Total Capacity: 14,636 MW Traditional T&D Leveraged Leases 2006E Operating Earnings(1)(2): $875M - $950M 2006 EPS Guidance(1)(2): $3.45 - $3.75 Assets (as of 12/31/05): $ 29.8B Domestic/Int'l Energy Regional Wholesale Energy Includes the parent impact of $(60-70)M Income from Continuing Operations, excluding merger-related costs (3) Income from Continuing Operations, excluding merger-related costs of $3M for PSE&G and $12M for PSEG Power 2005 Results: $347M(3) $418M(3) $196M 2006 Range: $250M - $270M(2) $500M - $550M(2) $185M - $205M

2005 2006 1.35 1.35 1.37 activity 1.6 1.47 negative activity 0.25 0.02 0.09 Power Nuclear Operations $.16 Recontracting & Higher Margins $.31 BGSS ($.13) MTM ($.07) Depreciation on New Assets ($.11) O&M ($.08) Additional Shares & Other ($.06) $/Share Holdings Prior year gains Eagle Point, MPC, SEGS ($.14) Taxes ($.04) Texas Ops $.15, including MTM of $.04 2005 United Lease Write-off $.06 FX Gains/Losses $.04 Other $.02 PSE&G Transmission $.03 Weather ($.10) Excess Depreciation Credit ($.08) Depreciation & Amortization ($.02) O&M & Other ($.06) Additional Shares ($.02) Year to Date Results - 2nd Quarter 2006 2006 Operating Earnings** 2005 Operating Earnings* * Excludes ($.07) Merger Costs and $.69 Discontinued Operations ** Excludes ($.03) Merger Costs, $.90 Discontinued Operations, and ($.70) loss on sale of RGE 1.47 ($.14)

PSEG Power Overview Nuclear Nuclear Operating Services Agreement 2005 - record output 2006 - year to date output exceeds 2005 at each unit Fossil Increased output over 2005 Improved performance Margin Growth 2006 - energy recontracting improvements 2007 and beyond - energy recontracting and capacity market improvements

NYMEX Natural Gas PJM West RTC Henry Hub $/MBTU PJM West RTC $/Mwh PJM Pricing Environment Electricity and Natural Gas Forward Price Movements 2003 - 2007

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

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

PSE&G / Holdings Overview PSE&G Providing safe, reliable, low-cost service Merger issues & rate relief requirements Manageable infrastructure improvements Energy Holdings Significant monetization / debt pay downs Stability in international operations Strong performance in Texas

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 $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 $3.75** to

Exelon Update Live Up to our Commitments Perform at World-Class Levels Disciplined Financial Management

Key Messages Demonstrated ability to deliver on our commitments Continued strong financial and operating performance Uniquely positioned generation business Changing composition of earnings Managing the transition to Illinois auctions Stable growth delivery businesses with improving operations Plan in place to ensure continued viability of ComEd while protecting Exelon Strong balance sheet and financial discipline

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

Note: See presentation appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS Meeting Our Financial and Operating Commitments 6/1/2006 6/1/2005 1.48 1.42 $1.48 $1.42 Jun-05 Jun-06 $1.40* $1.56* * Excludes $0.02/share favorable impact versus normal in 2005 and $0.08/share unfavorable impact versus normal in 2006, based on Exelon models First Half 2006 Highlights: ICC approved IL auction - proceeding as planned ICC order in ComEd rate case Higher generation margins Strong nuclear and fossil fleet performance Successful energy delivery system performance with record heat and new peaks Higher O&M expenses and capital expenditures Year-to-date Results:

Exelon Nuclear's sustained performance is a competitive advantage; June YTD capacity factor was 93.3% Range of Nuclear Capacity Factors (2001-2005) Sources: Platt's, Nuclear News, NRC and Department of Energy World-Class Nuclear Operations

2002 2003 2004 2005 2006E* 2007E* Generation 0.58 0.78 0.93 1.57 1.67 3.32 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 $4.48 as of 8/31/06 for Exelon stand-alone, not company guidance. 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)

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) The upcoming transition to power procurement auctions in Illinois reduces Generation's load- following risk, while allowing it to capture the full market value of its Midwest generation portfolio Generation currently supplies 100% of ComEd's POLR* load Post-2006, Generation is limited to supplying no more than 35% of ComEd's load through annual auctions Better fit with generation mix than current arrangement where Generation is sole supplier to ComEd Load obligations will be "slice of the system" - suppliers provide capacity, base load, intermediate and peaking energy and ancillary services Excess supply will be sold bi- laterally to other market participants * POLR = Provider of Last Resort

Managing the Transition to Power Auctions in IL The end of the ComEd PPA will allow Generation to better match assets with sales in the most profitable manner Generation and Load - Midwest Portfolio - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 2005 2006 2007 2008 2009 MWs 0 17,520 35,040 52,560 70,080 87,600 105,120 122,640 140,160 157,680 175,200 GWhrs Generation (ATC) Avg. Load (ATC) Peak Load obligation Hedging Region Note: Assumes 35% participation cap

Large and growing customer base Low-risk distribution assets Improving operations and customer satisfaction Transitioning out of rate freeze/cap environment ComEd: end of 2006 PECO: end of 2010 Energy Delivery's Competitive Position

ComEd Regulatory Update Distribution Rate Case ICC Order provided for $8M increase, vs. the Administrative Law Judges' (ALJs') Proposed Order of $164M and ComEd's original request of $317M On August 30, ICC voted 5-0 to grant key elements of ComEd's request for rehearing Due to the ICC Order, ComEd and Exelon will record an after-tax impairment charge of ~$741M in 3Q06 based on results of ComEd's interim goodwill impairment analysis IL Auction Illinois Supreme Court and Appellate Court denied the Illinois Attorney General's request to stay auction; Appellate Court will consider all appeals Auction begins September 5th (NJ auctions have taken 2-7 days to complete) Auction Manager and ICC Staff reports to the ICC (2 days after auction closes) ICC decides whether to reject or accept results (5 days after auction closes) Residential Rate Stabilization Case On August 29, ComEd submitted a modified plan that ICC Staff supports: "10/10/10" caps from 2007 to 2009; deferral recovery from 2010 to 2012 with 6.5% annual carrying charge An "opt-in" feature for customers to enroll through August 22, 2007 ICC decision anticipated late November 2006

2006 Performance Strategic Direction Operations and Regulatory Update Results of Financial Policy Alignment Initiative 2007 Financial Projections and Key Assumptions by Operating Company Annual Investor Conference Preview Given our changing business profile, we are taking a fresh look at all of our key financial policies to ensure optimal alignment Conference Agenda Exelon's Conference is scheduled for December 12th in Chicago Ensuring alignment of key financial policies: Commodity hedging Financing plan Liquidity Capital structure Credit targets Spending plan Capital expenditures O&M expenses Growth plan "Value Return" policy Dividends Share buy-backs Risk controls

Merger Update

Merger Update - NJ Negotiations NJ BPU approval is the final regulatory action needed to complete the merger Series of discussions conducted with parties in NJ to arrive at "best offer" proposal Exelon and PSEG Boards will reassess and make final decision once NJ requirements are known Exelon announced an approximate $55M pre-tax write-off of capitalized merger costs in 3Q06 due to management's determination that probability of merger completion is no longer "more likely than not"

Lehman Brothers 2006 CEO Energy/Power Conference New York City September 6, 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

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 * Weather normalized: 2004 - excludes $0.11/share unfavorable impact vs. normal; 2005 - excludes $0.12/share favorable impact vs. normal; 2006E - excludes $0.08/share unfavorable impact vs. normal Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP 2005 Guidance: $3.00 - $3.15 Strong earnings growth is continuing in 2006 and will accelerate in 2007 Adjusted (non-GAAP) operating EPS Guidance $2.89* $2.98*

Exelon Nuclear's production cost is consistently lower than the industry average; YTD cost was $14/MWh Range of Nuclear Production Costs (2001-2005) Source: Electric Utility Cost Group Exelon Nuclear Performance - Cost Management

2004 2005 2006 2007 2008 2009 2010 2011 Contracted 10700 8991 6923 8456 7311 8627 5042 3260 Flexibilities 1810 3517 1707 1571 186 70 Demand 8437 11587 8407 9765 7497 9378 8370 7874 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 prices in $20-25/lb. range due to new uranium production Exelon Nuclear is managing fuel costs Nuclear Performance - Fuel Costs

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 Exelon Power is well positioned to capitalize on market opportunities Exelon Power Performance - Reliability

Improved Delivery Service Performance Investing in T&D system Improving material condition of gas distribution system Completing high-impact maintenance Creating customer-focused culture Enhancing customer outage communications "Telling our story" through media outreach Achieved five-year high in customer satisfaction at PECO ComEd and PECO initiatives are leading to improved reliability and customer satisfaction

2004 & Q1-Q2 2005 8/31/05: Distribution case filed 2/25/05: Procurement case filed Rates frozen since 1997 and subsequently reduced 20%. ComEd's mitigation proposal would ease residential customers' transition to cost-based rates. New rates effective January 2, 2007. 12/16/05: FERC confirms auction meets its principles 1/11-5/4/06: Legislative session 1/24/06: ICC votes 5-0 for reverse auction Sept. '06: Initial auction to take place Meeting the Regulatory Challenge 6/8/06: ALJ proposed order 8/30/06: ICC voted to rehear certain issues Q3-Q4 2005 Q1-Q2 2006 Q3-Q4 2006 Nov. '06: Veto session Dec '04: Post-'06 Final ICC Staff Report supported auction process Procurement Case Distribution Case Legislative Session 5/23/06: Stabilization case filed 8/29/06: Filed modified plan Residential Rate Stabilization Case 11/29/06: ICC order requested 7/26/06: ICC order issued

ComEd Rate Case Summary While the Administrative Law Judges' (ALJs) Proposed Order provided for a revenue increase of $164M compared to ComEd's original request of $317M, the ICC Order provided for only an $8M increase ($ in millions) Revenue Requirement Revenue Increase Original request $1,895 $317 Final position - ComEd brief $1,857 ($38) ROE @ 10.045% / Capital Structure @ 42.86% equity $1,732 ($125) Pension asset $1,662 ($70) Administrative & General expenses $1,601 ($61) ComEd incentive compensation $1,591 ($10) Other ICC adjustments $1,586 ($ 5) Approved increase in distribution rate revenue $8M

ComEd Rate Case Update The ICC Order provided for only an $8M increase, versus the Administrative Law Judges' (ALJs') Proposed Order of $164M and ComEd's original request of $317M On August 30, ICC voted 5-0 to rehear several key issues that ComEd sought for rehearing ICC has 150 days to complete rehearing process Key issues on rehearing Administrative & General Expense: Seeking approval of disallowed costs ($61M improvement to ICC Order) Pension Asset: Seeking to recover pension expense as if ComEd had funded contribution through debt or, alternatively, to recover pension expense as if contribution had never been made ($27-$35M improvement to Order) Common Equity Ratio: Seeking to establish a 46% common equity ratio as recommended in ALJs' Proposed Order, rather than the ICC Order's 42.86% common equity ratio ($17M improvement to Order) Governmental Consolidated Billing (GCB) Rider: Seeking to either eliminate the Rider or ensure acceptable allocation of annual subsidy ($36-$62M) to other customers

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.

Post Auction Processes Conduct Auction NERA will be the Auction Manager under the oversight of the ICC Staff The auction is conducted in rounds for which the Auction Manager announces a price for each product Bidders bid for number of tranches they would serve for each product at the announced prices If excess supply, price for product is reduced in the next round until no excess is left Bidders holding final bids when auction closes are the winners Within 2 business days of auction close, Auction Manager and ICC Staff issue confidential reports to the Commission Within 5 business days of auction close, Commission decides if it will initiate investigation - if no investigation, results will go into effect ComEd files compliance tariffs with final retail rates ComEd signs Supplier Forward Contracts with winning suppliers within 3 business days after ICC review Enrollment window for customers 400 KW-3 MW begins Auction Manager and Staff submit public report with winners 30 days prior to delivery 1/1/07 Power flows September 5 - ??? ~ September 8 - Jan 1, 2007 ComEd - Auction Process

PJM West Hub PJM NI Hub Source: OTC quotes and electronic trading systems. 4/19: $73.94 2/16: $61.56 4/20: $53.49 2/16: $43.80 7/6: $44.50 7/6: $62.18 2007 Around-the-Clock Historical Forward Prices As Exelon becomes a more commodity-driven business, wholesale power price movements will have an increasing impact on corporate earnings. 8/31: $65.27 8/31: $48.38

2004 and 2005 are actual settled prices. Real Time LMP (Locational Marginal Price) Next day over-the-counter market Average NYMEX settle prices 2006 information is a combination of actual prices through August 31, 2006 and market prices for the balance of the year 2007 and 2008 are forward market prices as of August 31, 2006 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 ($48.38/MWh on 8/31/06). (2) 2006 estimated price is a combination of actual ATC prices for PJM NiHub through August 31, 2006 and market prices for the balance of the year ($42.58/MWh). 81 2006 Est. Price (2) 2007 Forward (1) Break-Even Price for New Construction - 2006$

Exelon Consolidated: FFO / Interest 5.6x BBB 4.5x - 6.5x FFO / Debt 27% 30% - 45% Debt Ratio 53%(3) Generation: FFO / Interest 11.2x BBB+ 5.5x - 7.5x FFO / Debt 77% 40% - 55% Debt Ratio 35% ComEd: FFO / Interest 3.8x A- 3.5x - 4.2x FFO / Debt 17% 20% - 28% Debt Ratio 39%(3) PECO: FFO / Interest 5.5x A- 3.5x - 4.2 x FFO / Debt 19% 20% - 28% Debt Ratio 52% (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 $0.7 billion ComEd goodwill write off in 2006 Exelon's Balance Sheet is strong "A" Target Range (2) Projected 2006 Key Credit Measures S&P Credit Ratings(1)

GAAP EPS Reconciliation 2000-2002

GAAP EPS Reconciliation 2003-2005

GAAP EPS Reconciliation 1H 2006/2005 Six Months Ended June 30, 2006 and 2005 Six Months Ended June 30, 2006 and 2005 2005 GAAP Reported EPS $1.53 Mark-to-market (0.03) Investments in synthetic fuel-producing facilities (0.07) Charges associated with Exelon's anticipated merger with PSEG 0.01 2005 financial impact of Generation's investment in Sithe (0.02) 2005 Adjusted (non-GAAP) Operating EPS $1.42 2006 GAAP Reported EPS $1.55 Mark-to-market (0.03) Investments in synthetic fuel-producing facilities 0.06 Charges associated with Exelon's anticipated merger with PSEG 0.02 Nuclear decommissioning obligation reduction (0.13) Severance charges and 2006 financial impact of Generation's prior investment in Sithe 0.01 2006 Adjusted (non-GAAP) Operating EPS $1.48

2006 Exelon Earnings Guidance Exelon's outlook for 2006 adjusted (non-GAAP) operating earnings excludes the earnings impacts of the following: mark-to-market adjustments from non-trading activities investments in synthetic fuel-producing facilities certain costs associated with the proposed merger with PSEG significant impairments of intangible assets, including a potential impairment of ComEd's goodwill in the third quarter significant changes in decommissioning obligation estimates certain amounts to be recovered by ComEd as approved in the July 26, 2006 ICC rate order, specifically, previously incurred severance costs and losses on extinguishments of long-term debt other unusual items, including any future changes to GAAP

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.