Value Driven John F. Young Executive Vice President & Chief Financial Officer Edison Electric Institute Conference Las Vegas, Nevada November 5-8, 2006

Exelon Investor Relations Contacts Inquiries concerning this presentation should be directed to: Exelon Investor Relations 10 South Dearborn Street Chicago, Illinois 60603 312-394-2345 312-394-4082 (Fax) For copies of other presentations, annual/quarterly reports, or to be added to our email distribution list please contact: Felicia McGowan, Executive Admin Coordinator 312-394-4069 Felicia.McGowan@ExelonCorp.com Investor Relations Contacts: Joyce Carson, Vice President 312-394-3441 Joyce.Carson@ExelonCorp.com JaCee Burnes, Director 312-394-2948 JaCee.Burnes@ExelonCorp.com Marybeth Flater, Manager 312-394-8354 Marybeth.Flater@ExelonCorp.com Len Epelbaum, Principal Analyst 312-394-7356 Len.Epelbaum@ExelonCorp.com

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 to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon Corporation's 2005 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 20, ComEd-Note 17, PECO-Note 15 and Generation-Note 17; (2) Exelon Corporation's Third Quarter 2006 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). 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 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 The Exelon Story ComEd PECO Exelon Generation Exelon Today's discussion will focus on "The Next Five Years", including earnings drivers for 2007 - 2011 by Operating Company

The Exelon Story - Value Driven Demonstrated ability to add value during transformation from an integrated utility to a predominantly merchant generator Premier U.S. nuclear generator uniquely positioned to capture market opportunities through operational and commercial excellence Primary source of Exelon's value going forward ~10% average annual operating EPS growth since inception Continued strong growth trend through 2011 Strong balance sheet and financial discipline Realigning value return framework Experienced management team Predictable source of earnings through transition period; preparing for 2011 Completing the transition to a "wires-only" business with a regulatory recovery plan in place Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP

'05 Earnings(1): $1,125M '06E Earnings(3): $1,250 - $1,320M '05 EPS(1): $1.66 '06 EPS Guidance(3): $1.85 - $1.95 Credit Rating(4): BBB+ The Exelon Companies Pennsylvania Utility Illinois Utility Nuclear, Fossil & Hydro Generation Power Marketing '05 Earnings(1): $527M $533M '06E Earnings(3): $510 - $530M $410 - $440M '05 EPS(1): $0.78 $0.79 '06 EPS Guidance(3): $0.75 - $0.80 $0.60 - $0.65 Credit Ratings(4) : BBB A- '05 Operating Earnings(1): $2.1B '06E Operating Earnings (3): $2.1 - $2.2B '06 EPS Guidance(2): $3.15 - $3.30 Assets (12/31/05): $42.4B Credit Rating(4): BBB (1) 2005 Adjusted (Non-GAAP) Operating Earnings and Operating EPS (2) Revised 2006 Operating EPS Guidance (9/27/06) from previous $3.00 - $3.30 per share (3) Estimated 2006 Adjusted (Non-GAAP) Operating Earnings and 2006 Operating EPS Guidance (4) Senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP

Multi-Regional, Diverse Company Note: Megawatts based on Exelon Generation's ownership as of 12/31/05; excludes investments in two facilities in Mexico of 230 MWs. Generating Plants %MW Nuclear Hydro Coal Intermediate Peaker 50 5 9 7 29 Midwest Generation Owned: 11,300 MW Contracted: 5,291 MW Total: 16,591 MW ERCOT/South Generation Owned: 2,299 MW Contracted: 2,900 MW Total: 5,199 MW New England Generation Owned: 542 MW Mid-Atlantic Generation Owned: 10,958 MW Total Generation Owned: 25,099 MW Contracted: 8,191 MW Total: 33,290 MW Electricity Customers: 1.6M Gas Customers: 0.5M Electricity Customers: 3.7M

2000 2001 2002 2003 2004 2005 2006E East 1.93 2.24 2.41 2.61 2.78 3.1 3.15 0.3 Q3 Highlights Solid financial operating EPS results Higher generation margins Strong nuclear and fossil performance Higher O&M costs Unfavorable ICC Rate Order ComEd goodwill charge of $776M Rehearing process underway ICC approved IL auction Exelon Generation, one of 16 winning bidders in the auction YTD 2006 weather-normalized operating earnings are 11% higher than 2005 ~10% Average Annual Growth(1)(3) (1) See appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Excludes $0.10 per share favorable impact versus normal in 2005 and $0.03 per share unfavorable impact versus normal in 2006, based on Exelon models (3) 5-yr growth rate; calculated using 2000 Operating EPS of $1.93 per share as base year Strong Financial Performance Historical Operating EPS Year-to-date EPS Results Sep-05 Sep-06 Adjusted (non-GAAP) EPS(1) Operating $2.37 $2.50 Weather Normalized(2) $2.27 $2.53

ComEd Operating Earnings: 2007 Estimate As a "wires-only" company, ComEd was always expected to earn less on an operating basis in 2007 than in prior years. The unfavorable ICC Order in the Distribution Case further depressed ComEd's 2007 earnings outlook. 510 250 80 20 50 55 - End of transition period - Regulatory lag ('04 Test Yr) Inflation CapEx - Depreciation + DST rate request + Load growth - DST disallowance(2) + DST rehearing outcome $510M - $530M $250M - $300M $80M - $135M (1) 2006 Operating Earnings Guidance; see appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Reflects disallowance of pension asset and A&G expenses and modified capital structure and ROE; refer to Appendix for details (3) Preliminary 2007 Operating Earnings Guidance which will be updated at Exelon's Annual Investor Conference on 12/12/06 Risks & Opportunities +/- Load growth +/- Spending +/- DST rehearing outcome +/- Transmission rate case outcome Key Assumptions(3) Rate Base: $7.6B Equity: ~43% ROE: 2.5 - 4.1% Based on ComEd's Request in the Delivery Service Tariff (DST) Case Based on the ICC Order in the DST Case 2006 Guidance(1) 2007 - DST Request 2007 Preliminary Guidance(3)

Low 80 55 ComEd Operating Earnings: Next Five Years $80M - $135M 2007 - 2011 Earnings Drivers Regular DST Rate Requests (Minimize Regulatory Lag) Rate Base Growth Load Growth After 2007, assuming no rate freeze legislation or similar event, ComEd's earnings are expected to increase as regulatory lag is reduced over time through regular rate requests, putting ComEd on a path toward appropriate returns and solid credit metrics Executing ComEd's Regulatory Recovery Plan Investment is required over the next five years to: Maintain and improve the reliability of ComEd's system Meet growing customer requirements Improve customer service 2011 ComEd - 2011 Assumptions Rate Base: ~$9.6B Equity: ~45% ROE: ~10% 2007 Preliminary Guidance(1) (1) Preliminary 2007 Operating Earnings Guidance which will be updated at Exelon's Annual Investor Conference on 12/12/06

Important ComEd Milestone: Purchased Power Cost Recovery ICC authorized recovery of purchased power costs in the Distribution Case Rate Order - July 2006 Illinois auction approved - September 2006 Culmination of nearly three-year process to approve procurement methodology Resulted in customer rates lower than those in 1995 Implications of a rate freeze extension (if proposed legislation were enacted and upheld) ComEd would pay substantially more for its purchased power and operating costs than it would be allowed to collect Would result in a significant cash flow deficit which would ultimately drive ComEd into insolvency and bankruptcy

PECO Average Electric Rates 2006 2.59 0.46 2.7 4.92 2007 2.59 0.46 2.7 5.43 2008 - 2010 2.59 0.46 2.7 5.43 2011 2.59 0.46 9.09 Energy / Capacity Competitive Transition Charge Transmission Distribution 10.67¢ 11.18¢ 11.18¢ Unit Rates (¢/kWh)(1) (1) Rates increased from original settlement by 1.6% to reflect the roll-in of increased Gross Receipts Tax and $0.02/kWh for Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustment (2) Assumes $55.08/MWh PJM West ATC price (2011) with a $7.15/MMBTU gas price at Henry Hub as of 10/3/06 per The Northbridge Group 12.14¢ Electric Restructuring Settlement Current Post Transition Projections(2) Projected 2011 rates reflect the end of PECO's transition period and the termination of the CTC +8.6% +4.8%

PECO Expected Rate Base 2007 2008 2009 2010 2011 Distribution Rate Base 2.5 2.6 2.8 2.9 3 Transmission Rate Base 0.5 0.5 0.5 0.5 0.6 Gas Rate Base 1 1.1 1.1 1.1 1.2 CTC Rate Base 3 2.4 1.7 0.9 $- Change in rate base is amortization of stranded assets offset by CapEx - Depreciation Post transition, PECO's rate base is expected to be ~$4.7 billion Transmission Gas CTC Distribution $7.0 $6.6 $6.0 $5.4 $4.7 $ in billions (as of beginning of year)

Low 410 400 30 30 PECO Operating Earnings: Next Five Years $410M - $440M PECO is expected to provide a predictable source of earnings to Exelon through the remainder of the transition period PECO - 2011 Assumptions Rate Base: ~$4.7B Equity: ~50% ROE: ~10% 2006 Guidance(1) 2011 2006 - 2011 Earnings Drivers Load growth CTC amortization Inflationary pressures 2007 Preliminary Guidance(2) $400M - $430M (1) 2006 Operating Earnings Guidance; see appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Preliminary 2007 Operating Earnings Guidance which will be updated at Exelon's Annual Investor Conference on 12/12/06

Exceptional generation business uniquely positioned to capture value of: Large, low-cost, low-emissions, well-run nuclear fleet Upside from end of below-market POLR contracts in Illinois and Pennsylvania Tightening reserve margins Exelon Generation captures market opportunities and rigorously manages risk through operational and commercial excellence Exelon Generation Value Proposition

EXC 93.1% Nuclear Operations: Sustained Performance Exelon Nuclear's sustained performance is a competitive advantage; September 2006 YTD capacity factor was 94.1% Sources: Platt's, Nuclear News, NRC and Department of Energy Range of Nuclear Capacity Factors (2001-2005)

Nuclear Operations: Track Record of Excellence The Exelon Nuclear model works - and is scalable Scalability of Exelon Model 1998 1999 2000 2001 2002 2003 2004 2005 2006 Unicom 64.88140641 89.59640843 94.37956501 93.85704678 PECO 85.68843377 93.09515073 94.19145057 93.85704678 AmerGen 55.32715176 80.08022081 87.29569979 93.85704678 Exelon 93.85704678 92.71109321 93.16393546 93.56327136 93.44230558 93.9 PSEG 80.84978756 83.28743286 86.4037593 89.23563154 91.09913704 86.17144839 76.98987036 PSEG with NOSC 76.98987036 89.05903423 92.7 (1) Nuclear Operating Services Contract with PSEG Nuclear (1) Capacity Factor (%)

Nuclear Going Forward Recently announced intent to apply for Construction & Operating License ("COL") in ERCOT by end of 2008 Preserves option to participate in Energy Policy Act incentives Supports NRC resource planning New nuclear designs offer improved features, passive safety systems, competitive capital costs and shorter construction times ERCOT is an attractive market for new nuclear Growing demand for power and robust market prices State and local support for new nuclear Provides emissions-free generation in an area with air quality concerns Existing presence in ERCOT Exelon's phased approach allows for go/no-go decisions at major funding/commitment milestones

Total Portfolio Characteristics 2006 2007 Nuclear 139300 139200 Fossil & Hydro 32000 37400 Forward / Spot Purchases 29300 7400 2006 2007 Load (2006: ComEd & PECO, 2007: PECO) 118900 40500 Actual & Expected Forward Hedges 71900 131100 Open Position 9800 12400 Expected Total Supply Expected Total Sales Includes Illinois load auction results GWh GWh Note: 2007 position is projected as of end of 2006 The value of our portfolio resides predominantly in our Nuclear fleet

Total Portfolio Revenue Net Fuel Load Nuclear & Hedges Other Supply Total 2006 -1200 5700 350 4850 2007 -950 6850 700 6600 2007 2006 Legend Total Portfolio Revenue Net Fuel Increase ('06-'07): ~$1,750M + $250M + $1,150M + $350M Expiration of below market ComEd PPA offset by higher cost-to-serve PECO PPA Improved nuclear performance and higher power prices Includes: South, New England, Exelon Energy, and all non-nuclear supply in Midwest & Mid Atlantic +1,750M ($ in millions, pre-tax)

Recent Examples Supplemented portfolio with load following products Maintained length for opportunistic sales Used physical and financial fuel products to manage variability in fossil generation output Deployed option strategies in the Midwest and Mid-Atlantic to protect against retail load switching and price volatility Power Team creates value by capturing the upside, protecting the downside, and translating operational excellence into earnings Portfolio Management Over Time % Hedged Operating Profit ($ Million) % Hedged High End of Profit Low End of Profit Open Generation with Load Only Portfolio Optimization Portfolio Management Portfolio Management

Flexibility in our targeted financial hedge ranges allows us to be opportunistic while mitigating downside risk Definition Percent Financially Hedged is our estimate of the gross margin that is not at risk due to a market price drop and assuming normal generation operating conditions The formula is: 1 - (Gross margin at the 5th percentile / Expected Gross margin) Target Financial Hedge* Range Target Financial Hedge* Range Target Financial Hedge* Range Prompt Year Second Year Third Year 90% - 98% 70% - 90% 50% - 70% Reduce earnings risk created by market and portfolio uncertainties Link hedging requirements to: Future cash requirements: capital expenditures, debt payments Credit objectives Value return policy Consider various sources of risk Market, Credit, Operational Commodity Hedging Targets

Exelon Generation Operating Earnings: Next Five Years $1,250M - $1,320M Exelon Generation is poised for earnings growth over the next five years driven by the end of the IL and PA transition periods and its unique competitive position 2006 Guidance(1) 2011 2007 (1) 2006 Operating Earnings Guidance; see appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS 2007 - 2011 Earnings Drivers End of PECO PPA (2011+) Market conditions - Heat Rate - Capacity - Carbon Inflationary pressures Higher nuclear fuel costs 2006 - 2007 Earnings Drivers End of ComEd PPA Market conditions PECO transfer price Inflationary pressures TXU toll Higher nuclear fuel costs Nuclear COL costs

Exelon's changing composition of earnings warrants a new value return policy Existing dividend policy based on a business mix in which the regulated utilities contributed a larger share of earnings Existing share repurchase program designed solely to offset dilution from shares issued under Exelon's incentive plans The new policy will: Establish a base dividend Return excess cash and/or balance sheet capacity through share repurchases After funding maintenance capital and committed dividends In absence of higher value-added growth opportunities Maintain adequate credit metrics on a prospective basis Details of the Value Return Policy will be discussed at Exelon's Annual Investor Conference on December 12th, 2006 Value Return Policy

2006 Exelon Investor Conference The Swissotel Chicago 323 East Wacker Drive December 11th & 12th December 11th - Pre-Conference 6:00 - 10:00pm - Reception & Dinner The Field Museum December 12th - Conference 7:15AM: Registration & Breakfast 8:00AM: Conference Program Grand Ballroom, The Swissotel Chicago Conference Topics 2006 Performance Strategic Outlook 2007 Earnings Guidance by Operating Company Operating Company Updates Balance Sheet Value Return Plan

Value Driven

Appendix - Financial and Operational Statistics

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 BBB 5.5x - 7.5x FFO / Debt 17% 40% - 55% Debt Ratio 39%(3) PECO: FFO / Interest 5.5x A- 3.5x - 4.2 x FFO / Debt 19% 20% - 28% Debt Ratio 52% Notes: Exelon consolidated, ComEd and PECO metrics exclude securitization debt. See last page of Appendix for FFO (Funds from Operations)/Interest and and FFO/Debt reconciliations to GAAP. (1) Current senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO as of 10/31/06; (2) Based on S&P Business Profiles: 7 for Exelon, 8 for Generation and ComEd, and 4 for PECO; (3) Reflects $0.8 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)

Value Return Framework After meeting commitments and analyzing value creation opportunities, free cash flow and/or balance sheet capacity will be used to return value to shareholders Free Cash Flow before Dividends and CapEx Committed Dividends Return Value via Share Repurchase, Increased Dividends Monetize Invest in Growth CapEx Strengthen Balance Sheet / Increase Financial Flexibility LESS: EQUALS: Cash Available Balance Sheet Capacity Invest in M&A IF > 0 And / Or Maintenance Capital

ComEd Expected Rate Base 2007 2008 2009 2010 2011 Distribution 5.9 6.4 6.8 7.2 7.7 Transmission 1.6 1.8 1.8 1.9 1.9 Transmission Distribution $ in billions (as of beginning of year) $7.6 $8.2 $8.6 $9.1 $9.6

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 9/14/06: Auction results approved ComEd Regulatory Calendar 6/8/06: ALJ proposed order 8/30/06: ICC voted to rehear certain issues; Order anticipated year-end Q3-Q4 2005 Q1-Q2 2006 Q3-Q4 2006 11/14-16 & 11/28-30: 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 10/25/06: ALJ Order recommended modified plan Residential Rate Stabilization Case Late Nov: ICC order 7/26/06: ICC order issued

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 Due to the ICC Order, ComEd and Exelon recorded an after-tax impairment charge of ~$776M in 3Q06 based on results of ComEd's interim goodwill impairment analysis On August 30, ICC voted 5-0 to grant key elements of ComEd's request for rehearing (ICC has 150 days to complete rehearing process) Key issues on rehearing Administrative & General Expense: Seeking approval of disallowed costs ($62M 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 ($25-$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 ($116M) to other customers ICC order anticipated by year-end

ComEd Regulatory Update (cont'd) 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 Phase-in plan is optional (residential customers may "opt-in" through August 22, 2007) A similar program at Potomac Electric experienced "opt-in" participation rates of 2-3% On October 25, the Administrative Law Judge recommended ICC approval of ComEd's plan ICC decision anticipated late November 2006

Adding Value for Illinois Consumers 10 Year Price Trends (in % price increases 1996 - 2006) Sources: 10-Year Price Trends: CPI, City Average for all Urban Consumers, Dept of Labor, Bureau of Labor Statistics Electricity Rates in Major Cities: Edison Electric Institute (EEI) -- Typical Bills and Average Rates Report, Winter 2006, pp. iii - iv Analysis represents the top 10 largest metropolitan areas served by investor-owned utilities (excluding Houston and Dallas). CenterPoint Energy and TXU did not participate in the EEI study. Electricity Rates in Major Cities (2005 Residential Rates, in cents per kWh) Gasoline Utility (piped) gas Medical Care Fruits and Vegetables Rent Bread Public Transportation ComEd (Today) ComEd (22% Increase) Average Rate (excl. ComEd): 11.9 cents

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

Post Auction Processes Conduct Auction NERA Economic Consulting was the Auction Manager under the oversight of the ICC Staff The auction was conducted in rounds for which the Auction Manager announced a price for each product Bidders bid for number of tranches they would serve for each product at the announced prices Bidders holding final bids when auction closed were the winners On 9/12 (within 2 business days of auction close), the Auction Manager and ICC Staff issued confidential reports to the ICC On 9/14 (within 5 business days of auction close), the ICC approved the auction for fixed-price customers On 9/15 (within 5 business days of auction close), NERA announced clearing prices and winning suppliers On 9/20 (within 3 business days from the date the Auction Manager released prices and bidder names), ComEd signed Supplier Forward Contracts with winning suppliers On 9/21, ComEd filed compliance tariffs with final retail rates Next Steps: Auction Manager and ICC Staff submit public report with winners and volumes 30 days prior to power delivery (~12/1/06) Power flows on 1/1/07 Rates effective on 1/2/07 September 5 - 8, 2006 September 8 - January 2, 2007 ComEd - Auction Process

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.

Illinois Auction Results Ancillary services Load shape Congestion Risk premium Capacity Other Costs: ATC Energy Price** ComEd energy 48.5 adder 15 $63.76/MWh (Blended Price*) ~ $15 ~$48 - $49 Winning Bidders: Ameren Energy Marketing American Electric Power Conectiv Energy Supply Constellation Energy Commodities DTE Energy Trading Dynegy Power Marketing Edison Mission Marketing & Trading Energy America Exelon Generation FPL Energy Power Marketing J. Aron & Company J.P. Morgan Ventures Energy Morgan Stanley Capital Group PPL EnergyPlus Sempra Energy Trading WPS Energy Services Illinois fixed priced auctions declared successful * Blended price for residential and small commercial customers (the average of the three CPP-B products) ** Range of 2007 and 2008 NI Hub ATC prices over the auction bidding period (Sept. 5 - Sept. 8, 2006) ComEd Auction Results

2007 2008 2009 2010 2011 FERC activity on Transmission Rate Design PJM & PJM/MISO Potential Gas Rate Case POLR Rates Effective (1/1/11) Filing per Regulations (10/09) PUC issues final POLR Regulations Transmission Gas POLR Plan for Major Regulatory Filings

Load Nuclear & Hedges Other Supply Total 2006 -750 3250 -50 2450 2007 0 3950 50 4000 2007 2006 Legend Midwest Revenue Net Fuel Increase ('06-'07): ~$1,550M Expiration of below market PPA Improved nuclear performance and higher power prices +$750M +$700M +$100M +$1,550M ($ in millions, pre-tax) Midwest Revenue Net Fuel

Mid-Atlantic Revenue Net Fuel Load Nuclear & Hedges Other Supply Total 2006 -450 2450 450 2450 2007 -950 2900 650 2600 2007 2006 Legend Mid-Atlantic RNF Increase ('06-'07): ~$150M ($500M) + $450M + $200M Higher prices / increased cost-to-serve Improved Nuclear performance and higher power prices +150M ($ in millions, pre-tax)

South Revenue Net Fuel Generation & Hedges Total 2006 -40 -40 2007 -50 -50 2007 2006 Legend Total Portfolio RNF Decrease ('06-'07): ~($10)M ($10M) Higher spark spreads offset by roll-off of income from the TXU toll agreement ($10M) ($ in millions, pre-tax)

2006 2007 Nuclear 90700 91100 Coal 9000 10000 Forward/Spot Purchases & Other Generation 14900 2100 Midwest Portfolio Characteristics 2006 2007 ComEd Load 79100 0 Actual and Expected Forward Hedges 31400 95000 Open Position 4100 8200 Expected Midwest Supply Expected Midwest Sales Includes Illinois load auction results GWh GWh Note: 2007 position is projected as of end of 2006

Mid-Atlantic Portfolio Characteristics 2006 2007 Nuclear 48600 48100 Fossil & Hydro 11500 12100 Forward / Spot Purchases 8750 5900 2006 2007 PECO Load 39800 40500 Actual & Expected Forward Hedges 25100 22300 Open Position 3950 3300 Expected Mid-Atlantic Supply Expected Mid-Atlantic Sales GWh GWh Note: 2007 position is projected as of end of 2006

South Portfolio Characteristics 2006 2007 Generation 10800 13600 Forward / Spot Purchases 6300 1100 2006 2007 Actual & Expected Forward Hedges 15400 13800 Open Position 1700 900 Expected South Supply Expected South Sales GWh GWh Note: 2007 position is projected as of end of 2006

Nuclear Performance - Cost Management Exelon Nuclear's production cost is consistently lower than the industry average; September 2006 YTD cost was $13.71/MWh Range of Nuclear Production Costs (2001-2005) Source: Electric Utility Cost Group. Exelon data excludes Salem. EXC

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, INPO, Electric Utility Cost Group. Exelon data excludes Salem.

Nuclear Performance - Fuel Costs Uranium market prices have increased, but Exelon is managing its portfolio Reduced uranium demand by 25% Contracting strategy protects us and ensures we are significantly below current spot market prices through 2011 Uranium is small component of total production cost Expect long-term fundamentals in $25-35 range due to new uranium production Exelon Nuclear is managing fuel costs

Announced Nuclear Projects 17 projects totaling ~35,000 MWs have been announced Company Owner Site State Type of Site Technology MWs COL Submission Date NuStart TVA/Southern Bellefonte Alabama Characterized site AP1000 (2 units) 2,234 Oct-07 NuStart Entergy Grand Gulf Mississippi Operating Nuclear Site ESBWR (1 unit) 1,520 Nov-07 Dominion Dominion North Anna Virginia Operating Nuclear Site ESBWR (1 unit) 1,520 Nov-07 Constellation Constellation Calvert Cliffs Maryland Operating Nuclear Site EPR (2 units) 3,200 Q4 07 Constellation Constellation Nine Mile Point New York Operating Nuclear Site EPR (2 units) 3,200 Q4 07 Duke Duke/Southern Lee (Cherokee) South Carolina Characterized site AP1000 (2 units) 2,234 Oct-07 Entergy Entergy River Bend Louisiana Operating Nuclear Site ESBWR (1 unit) 1,520 May-08 Progress Progress Harris North Carolina Operating Nuclear Site AP1000 (2 units) 2,234 Oct-07 Progress Progress TBD Florida Greenfield TBD TBD Jul-08 SCEG SCANA/Santee Cooper Summer South Carolina Operating Nuclear Site AP1000 (2 units) 2,234 Oct-07 Southern Southern Vogtle Georgia Operating Nuclear Site AP1000 (2 units) 2,234 Mar-08 FPL FPL TBD Florida TBD TBD TBD TBD NRG Energy NRG South Texas Proj. Texas Operating Nuclear Site ABWR (2 units) 2,700 mid-2007 Ameren Ameren Callaway Missouri Operating Nuclear Site TBD TBD TBD TXU Energy TXU Energy Comanche Peak Texas Operating Nuclear Site TBD 2,000 Dec-08 TXU Energy TXU Energy TBD Texas TBD TBD 2-6,000 Dec-08 Exelon Exelon TBD Texas TBD TBD TBD Dec-08

Energy Policy Act - Nuclear Incentives Production Tax Credit (PTC) $18 per MWh, 8 year PTC for first 6,000 MWe of new capacity Cap of $125M per 1,000 MWe of capacity per year Protects against a decrease in market prices and revenues earned Significantly improves EPS Benefit will be allocated/ prorated among those who: File COL by year-end 2008 Begin construction (first safety-related concrete) by 1/1/2014 Place unit into service by 1/1/2021 Government Loan Guarantee Results in ability to obtain non-recourse project financing Up to 80% of the project cost, repayment within 30 years or 90% of the project life Need clarification of implementation specifics Availability of funds to nuclear projects at risk given latest program guidelines Regulatory Delay "Backstop" "Insurance" protecting against regulatory delays in commissioning a completed plant First two reactors would receive immediate "standby interest coverage" including replacement power up to $500M The next four reactors would be covered up to $250M after six months of delay Energy Policy Act provides financial incentives and reduced risk by way of production tax credits and loan guarantees

Market implied heat rate NYMEX Historic Fwd. Gas Commodity Hedging - Transition to Market in the Midwest Power Team utilized put options in power and natural gas to smoothly transition to the load auction. The recent increase in market implied heat rates enhanced the value of our gas hedge.

PJM West Hub PJM NI Hub 4/19: $73.94 2/16: $61.56 4/20: $53.49 2/16: $43.80 9/28: $56.81 9/25: $43.01 Source: OTC quotes and electronic trading systems. 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.

Current Market Prices 1) 2004 and 2005 are actual settled prices. 4) Average NYMEX settled prices 2) Real Time LMP (Locational Marginal Price) 5) 2006 information is a combination of actual prices through October 27, 2006 and forward market prices for the balance of the year 3) Next day over-the-counter market 6) 2007 and 2008 are forward market prices as of October 27, 2006

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 ($45.29/MWh on 10/27/06). (2) 2006 estimated price is a combination of actual ATC prices for PJM NiHub through 10/27/06 and market prices for the balance of the year ($42.08/MWh). 81 2006 Est. Price (2) 2007 Forward (1) Break-Even Price for New Construction - 2006$

Appendix - GAAP EPS Reconciliation

GAAP EPS Reconciliation 2000-2002

GAAP EPS Reconciliation 2003-2005

GAAP EPS Reconciliation Nine Months Ended Sep. 30, 2006 and 2005 2005 GAAP Reported EPS $2.60 Mark-to-market (0.11) Investments in synthetic fuel-producing facilities (0.11) Charges related to proposed merger with PSEG 0.02 Reduction in severance reserves (0.01) 2005 financial impact of Generation's investment in Sithe (0.02) 2005 Adjusted (non-GAAP) Operating EPS $2.37 2006 GAAP Reported EPS $1.48 Mark-to-market (0.11) Investments in synthetic fuel-producing facilities 0.08 Charges related to proposed merger with PSEG 0.09 Severance charges 0.02 Nuclear decommissioning obligation reduction (0.13) Recovery of debt costs at ComEd (0.08) Impairment of ComEd's goodwill 1.15 2006 Adjusted (non-GAAP) Operating EPS $2.50

GAAP Earnings Reconciliation Year Ended December 31, 2005 (in millions) ComEd PECO ExGen Other Exelon 2005 GAAP Reported Earnings (Loss) $(685) $517 $1,098 $(7) $923 Mark-to-market - - 10 - 10 Investments in synthetic fuel-producing facilities - - - (81) (81) Charges related to proposed merger with PSEG 2 12 4 - 18 Severance (6) 1 1 - (4) Impairment of goodwill at ComEd 1,207 - - - 1,207 2005 financial impact of Generation's investment in Sithe - - (18) - (18) Cumulative effect pursuant to adopting FIN 47 9 3 30 - 42 2005 Adjusted (non-GAAP) Operating Earnings $527 $533 $1,125 $(88) $2,097

GAAP EPS Reconciliation Year Ended December 31, 2005 ComEd (a) PECO (a) ExGen (a) Other (a) Exelon (a) 2005 GAAP Reported Earnings (Loss) Per Share (b) $(1.02) $0.76 $1.62 $(0.01) $1.36 Mark-to-market - - 0.02 - 0.02 Investments in synthetic fuel-producing facilities - - - (0.12) (0.12) Charges related to proposed merger with PSEG - 0.02 0.01 - 0.03 Impairment of goodwill at ComEd 1.78 - - - 1.78 2005 financial impact of Generation's investment in Sithe - - (0.03) - (0.03) Cumulative effect pursuant to adopting FIN 47 0.01 0.01 0.04 - 0.06 Share differential (b) 0.01 - - - - 2005 Adjusted (non-GAAP) Operating Earnings Per Share $0.78 $0.79 $1.66 $(0.13) $3.10 Amounts shown per Exelon share. ComEd's GAAP loss per Exelon share is calculated using Exelon's basic shares. Exelon's GAAP Earnings Per Share is calculated using Exelon's diluted shares. ComEd's operating earnings per Exelon share is calculated using Exelon's diluted shares. As a result, amounts may not add across.

2006 - 2007 Exelon Earnings Guidance Exelon's outlook for 2006 - 2007 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 terminated merger with PSEG; significant impairments of intangible assets, including goodwill; significant changes in decommissioning obligation estimates; certain severance and severance-related charges; any impact of the ICC's July 26 order rehearing process in the fourth quarter of 2006; losses on extinguishments of long-term debt to be recovered by ComEd as approved in the July 26 ICC rate order; and other unusual items, including any future changes to GAAP

FFO Calculation and Ratios FFO Calculation 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 Debt Coverage FFO Debt Coverage FFO Adjusted Average Debt (1) Adjusted Average Debt (1) Adjusted Average Debt (1) Debt: Debt: Debt: LTD LTD LTD STD STD STD - Transition Bond Principal Balance - Transition Bond Principal Balance - Transition Bond Principal Balance Add debt equivalents: Add debt equivalents: Add debt equivalents: + A/R Financing + A/R Financing + A/R Financing + PV of Operating Leases + PV of Operating Leases + PV of Operating Leases = Adjusted Debt = Adjusted Debt = Adjusted Debt (1) Use average of prior year and current year adjusted debt balance (1) Use average of prior year and current year adjusted debt balance (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.

value driven
Exelon Corporation 2005-06 Fact Book

Table of Contents

Introduction	1
Exelon at a Glance
Profile, Vision and Quick Facts	2
Company Overview
Corporate Structure and Operating Company Summary	3
State Utility Regulation
Illinois Commerce Commission, ComEd Rate Case and Auction Structure	4
Pennsylvania Public Utility Commission, PECO Electric Transition Plan and System Average Electric Rates	5
Exelon – Financial and Operating Highlights	6
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP
Consolidated Statements of Income
Exelon Corporation	7
Commonwealth Edison Company (ComEd)	9
PECO Energy Company (PECO)	10
Exelon Generation Company	11
Exelon and Operating Companies
Capital Structure, Capitalization Ratios and Credit Ratings	12
Long-Term Debt Outstanding
Exelon Corporation	13
Exelon Generation	13
ComEd	14
PECO	15
Map of Exelon Service Area and Selected Generating Assets	16
Electric Sales Statistics, Revenue and Customer Detail
ComEd	17
PECO	19
Gas Sales Statistics, Revenue and Customer Detail – PECO	21
Exelon Generation
Generating Resources – Sources of Electric Supply, Type of Capacity and Long-Term Contracts	22
Nuclear Generating Capacity	23
Total Electric Generating Capacity	24
Fossil Emissions Reduction Summary	26
Electric Sales and Power Team Marketing Statistics	28
Power Team Marketing Statistics by Quarter	29

To the Financial Community,

The Exelon Fact Book is intended to provide historical financial and operating information to assist in the analysis of Exelon and its operating companies. Please refer to the SEC filings, including the annual Form 10-K and quarterly Form 10-Q, of Exelon and its subsidiaries for more comprehensive financial statements and information.

For more information about Exelon and to send e-mail inquiries, visit our website at www.exeloncorp.com.

Investor Information	Stock Symbol: EXC
Exelon Corporation	Common stock is listed on
Investor Relations	the New York Stock Exchange
10 South Dearborn Street
Chicago, IL 60603
312.394.2345
312.394.4082 (fax)

Information in this Fact Book is current as of October 31, 2006.

This publication 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 to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon Corporation’s 2005 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 20, ComEd-Note 17, PECO-Note 15 and Generation-Note 17; (2) Exelon Corporation’s Third Quarter 2006 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this publication. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this publication.

Exelon at a Glance

Company Profile

Exelon Corporation, headquartered in Chicago, Illinois, is one of the largest electric utilities in the U.S. with approximately 5.3 million customers and more than $15 billion in annual revenues. The company has one of the largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic.
our vision

Exelon will be the best electric and gas company in the United States. Working together, we will set the standard of excellence in the eyes of our customers, employees, investors and the communities we serve.

our goals

> Operate at world-class levels of safety, reliability, customer service and efficiency.

> Achieve competitive advantage through safe nuclear operations and environmental leadership.

> Create a rewarding and challenging workplace.

> Deliver superior value to customers and investors through disciplined financial management.

our values

safety
Safety is always our number one priority, for our employees, for our customers and for our communities.

integrity
We hold ourselves to the highest ethical standards in what we do and what we say.

customers
Our customers depend on us to keep the lights on and the gas flowing, and we commit to meeting their expectations.

diversity
We strive for diversity of people, experiences and viewpoints.

respect
We promote trust and teamwork by communicating openly and honestly with each other and our communities.

accountability
We live up to our commitments and take responsibility for our actions and results.

continuous improvement
We set stretch goals, work together to achieve them, measure our accomplishments and learn from the accomplishments of others.

Exelon Quick Facts at year-end 2005		Market Highlights
$15.4	6,764	666 million
billion in revenues	circuit miles of electric	common shares
	transmission lines	outstanding
$42.4	11,936	$1.60
billion in assets	miles of gas pipelines	current annual dividend rate
5.3	33,520	52%
million electric customers	MWs total generating	2005 dividend payout ratio
	resources
0.5	17,200	3.0%
million gas customers	employees	dividend yield
104,960
circuit miles of electric distribution lines

2

Company Overview

Exelon

Traditional Transmission and DistributionRegional Wholesale Energy

ComEd            PECO            Exelon An Exelon Company            An Exelon Company            Generation

Illinois Utility	Pennsylvania Utility	Nuclear Generation
2005	2005	Fossil Generation
(in millions)	(in millions)	Renewable/Hydro Generation
Revenues: $6,264	Revenues: $4,910	Power Marketing
Assets: $17,211	Assets: $10,018	2005
		(in millions)
		Revenues: $9,046
		Assets: $17,724

Operating Companies
Commonwealth Edison Company	PECO Energy Company	Exelon Generation
Commonwealth Edison (ComEd) is a regulated electricity transmission and distribution company with a service area in northern Illinois, including the City of Chicago, of approximately 11,300 square miles and an estimated population of 8 million. ComEd has approximately 3.7 million customers.	PECO Energy (PECO) is a regulated electricity transmission and distribution company and natural gas distribution company with a service area in south- eastern Pennsylvania, including the City of Philadelphia, of approximately 2,100 square miles and an estimated population of 3.8 million. PECO has approximately 1.6 million electric customers and 472,000 natural gas customers.	Exelon Generation includes the competitive electric generation operations, including owned and contracted-for generating facilities, and power marketing activities through Power Team.

3

State Utility Regulation

Illinois Commerce Commission (ICC)

The ICC has five full-time members, each appointed by the Governor (Rod Blagojevich, Democrat, elected in November 2002; term ends in January 2007) and confirmed by the Illinois State Senate. Commissioner Wright was appointed by former Governor George Ryan. The Commissioners serve for five-year, staggered terms. Under Illinois law, no more than three Commissioners may belong to the same political party. The Chairman is designated by the Governor.

Commissioner	Party Affiliation	Service Began	Term Ends	Professional Experience
Charles E. Box (Chairman)	Democrat	1/06	1/09	Attorney; mayor of Rockford, IL; city administrator and legal director
Kevin K. Wright	Independent	9/02	1/07	Deputy chief of staff to governor and secretary of state; state agency director
Lula M. Ford	Democrat	1/03	1/08	Assistant superintendent, Chicago Public Schools; teacher; assistant director, Central Management Service
Erin O’Connell-Diaz	Republican	4/03	1/08	Attorney; ICC Administrative Law Judge; assistant attorney general
Robert F. Lieberman	Democrat	2/05	1/10	CEO, Center for Neighborhood Technology; positions at Illinois Department of Natural Resources and Office of Coal Development

ComEd Electric Distribution Rate Case

		Revenue					Overall Rate		Return on
($ in millions)	Date	Increase		Test Year	Rate Base		of Return		Equity		Equity Ratio
ComEd Request	8/31/05	$	317	2004	$	6,187	8.94	%	11.00	%	54.20	%
ICC Order(a)	7/26/06	$	8	2004	$	5,521	8.01	%	10.045	%	42.86	%

(a) On August 30, 2006, the ICC granted in part, and denied in part, ComEd’s request for rehearing the July 26, 2006 rate order. The ICC has 150 days to issue an order on the rehearing.

Term Structures for Illinois Fixed Price Auctions

ComEd Energy Procurement Plan
(for customers <3 MW)

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. Transitional contracts are shown in black boxes.

CPP-B 33% of load3 years + 5 months3 years3 years3 years 33% of load2 years + 5 months3 years3 years3 years3 years > 33% of load17 months3 years3 years3 years3 years > CPP-A 17 months1 year 1 year 1 year 1 year 1 year 1 year 1 year 1 year 1 year 1 year 1 year calendar year2007 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

4

State Utility Regulation

Pennsylvania Public Utility Commission (PUC)

The PUC has five full-time members, each appointed by the Governor (Ed Rendell, Democrat, elected in November 2002; term ends in January 2007) and confirmed by the Pennsylvania State Senate. The Commissioners serve for five-year, staggered terms. Under Pennsylvania law, no more than three Commissioners may belong to the same political party as the Governor. The Chairman and Vice Chairman are designated by the Governor.

Commissioner	Party Affiliation	Service Began	Term Ends	Professional Experience
Wendell F. Holland (Chairman)	Democrat	9/03	4/08	Attorney; retired judge; executive at American Water Works Company
James H. Cawley (Vice Chairman)	Democrat	6/05	4/10	Attorney; majority counsel to the Pennsylvania Senate Consumer Affairs Committee
Kim Pizzingrilli	Republican	2/02	4/07	Secretary of the Commonwealth; positions at the Department of State and Treasury Department
Terrance J. Fitzpatrick	Republican	6/05	4/09	Attorney; PUC Commissioner 1999–2004 and former Chairman; PUC assistant counsel; member of the state Environmental Hearing Board

Vacancy^(a)

(a) Commissioner William R. Shane (D) left the PUC at the end of September 2006.

PECO Energy – Electric Transition Plan

The PUC authorized recovery in PECO’s 1998 settlement of $5.3 billion of stranded costs, or competitive transition charges (CTC) regulatory asset, with a return on the unamortized balance of 10.75%, through 2010. The PUC authorized amortization of the regulatory asset through 2010.

($ in millions)	Estimated		Estimated Stranded
Year	CTC Revenue		Cost Amortization
2005	$	808	$	404
2006		903		550
2007		910		619
2008		917		697
2009		924		783
2010		932		880

PECO Energy – Schedule of System Average Electric Rates

Transmission rates are regulated by the Federal Energy Regulatory Commission. The CTC rate is subject to annual reconciliation for actual retail sales. Rates increased from the original PUC settlement to reflect the roll-in of increased gross receipts tax and Universal Service Fund charge and nuclear decommissioning cost adjustment.

(¢/kWh)							Energy and
Effective Date	Transmission		Distribution		CTC		Capacity		Total
1/1/2005		0.46		2.47		2.44		4.65		10.02
1/1/2006		0.46		2.59		2.70		4.92		10.67
1/1/2007		0.46		2.59		2.70		5.43		11.18
1/1/2008		0.46		2.59		2.70		5.43		11.18
1/1/2009		0.46		2.59		2.70		5.43		11.18
1/1/2010		0.46		2.59		2.70		5.43		11.18

5

Exelon Corporation — Financial and Operating Highlights

	For the Years ended December 31,
(in millions, except per share data and where indicated)	2005		2004		2003(a)
Operating revenues	$	15,357	$	14,133	$	15,148
Net income	$	923	$	1,864	$	905
Electric deliveries (in GWhs)(b)		131,021		124,861		122,454
Gas deliveries (in million cubic feet (mmcf))		85,061		87,097		88,262
Total available electric supply resources (MWs)		33,520		34,687		41,744
Capital expenditures	$	2,165	$	1,921	$	1,954
Common Stock Data
Average common shares outstanding — diluted (in millions)		676		669		657
GAAP earnings per share (diluted)	$	1.36	$	2.78	$	1.38
Adjusted (non-GAAP) operating earnings per share (diluted)	$	3.10	$	2.78	$	2.61
Dividends paid per common share	$	1.60	$	1.26	$	0.96
New York Stock Exchange common stock price (per share)
High	$	57.46	$	44.90	$	33.31
Low	$	41.77	$	30.92	$	23.04
Year end	$	53.14	$	44.07	$	33.18
Book value per share	$	13.69	$	14.29	$	12.95
Total market capitalization (year end)	$	35,412	$	29,271	$	21,779
Common shares outstanding (year end)		666.4		664.2		656.4

(a) Common share data reflects 2-for-1 stock split effective May 5, 2004.

(b) One GWh is the equivalent of one million kilowatthours (kWh).

Reconciliation of Adjusted (non-GAAP) Operating Earnings Per Share to GAAP

	2005			2004			2003
GAAP Earnings per Diluted Share	$	1.36		$	2.78		$	1.38
Impairment of ComEd’s goodwill		1.78
Investments in synthetic fuel-producing facilities		(0.10	)		(0.10	)
Cumulative effect of adopting FIN 47		0.06
Charges related to the terminated merger with PSEG		0.03			0.01
Financial impact of Generation’s investment in Sithe Energies, Inc.		(0.03	)		0.02			0.27
Charges associated with debt repurchases					0.12
Severance charges					0.07			0.24
Cumulative effect of adopting FIN 46-R					(0.05	)
Settlement associated with the storage of spent nuclear fuel					(0.04	)
Financial impact of Boston Generating					(0.03	)		0.87
Cumulative effect of adopting SFAS No. 143								(0.17	)
Property tax accrual reductions								(0.07	)
Exelon Enterprises’ impairments								0.06
March 3, 2003 ComEd Settlement Agreement								0.03
Adjusted (non-GAAP) Operating Earnings per Diluted Share	$	3.10		$	2.78		$	2.61

6

Exelon Corporation — Reconciliation of Adjusted (non-GAAP) Operating Earnings
to GAAP Consolidated Statements of Income (unaudited)

	Twelve Months Ended December 31, 2005									Twelve Months Ended December 31, 2004
(unaudited, in millions,							Adjusted									Adjusted
except per share date)	GAAP(a)			Adjustments			Non-GAAP			GAAP(a)			Adjustments			Non-GAAP
Operating revenues	$	15,357		$	—		$	$15,357		$	$14,133		$	(248	)(l)	$	13,885
Operating expenses
Purchased power		3,162			(12	)(b)		3,150			2,709			20	(b),(l)		2,729
Fuel		2,484			20	(b)		2,504			2,220			(249	)(b),(l)		1,971
Operating and maintenance		3,718			(106	)(c),(d),(e)		3,612			3,700			(199	)(c),(d),(e),(i) ,(j)		3,501
Impairment of goodwill		1,207			(1,207	)(f)		—			—			—			—
Depreciation and amortization		1,334			(77	)(c),(e)		1,257			1,295			(57	)(c),(i)		1,238
Taxes other than income		728			—			728			710			(9	)(i)		701
Total operating expenses		12,633			(1,382	)		11,251			10,634			(494	)		10,140
Operating income		2,724			1,382			4,106			3,499			246			3,745
Other income and deductions Interest expense		(829	)		14	(c)		(815	)		(828	)		23	(c),(i)		(805	)
Equity in losses of unconsolidated affiliates		(134	)		104	(c)		(30	)		(154	)		84	(c)		(70	)
Other, net		134			—			134			60			40	(i),(k)		100
Total other income and deductions		(829	)		118			(711	)		(922	)		147			(775	)
Income from continuing operations before income taxes and minority interest		1,895			1,500			3,395			2,577			393			2,970
Income taxes		944			350	(b),(c),(d),(e)		1,294			713			373	(b),(c),(d),(e), (i),(j),(k)		1,086
Income from continuing operations before minority interest		951			1,150			2,101			1,864			20			1,884
Minority interest		—			—			—			6			—			6
Income from continuing operations		951			1,150			2,101			1,870			20			1,890
Income (loss) from discontinued operations		14			(18	)(g)		(4	)		(29	)		11	(l)		(18	)
Income before cumulative effect of changes in accounting principles		965			1,132			2,097			1,841			31			1,872
Cumulative effect of changes in accounting principles, net of income taxes		(42	)		42	(h)		—			23			(32	)(m)		(9	)
Net income	$	923		$	$1,174		$	2,097		$	1,864		$	(1	)	$	1,863

(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)	Adjustment to exclude the mark-to-market impact of Exelon’s non-trading activities (primarily at Generation).
(c)	Adjustment to exclude the financial impact of Exelon’s investments in synthetic fuel-producing facilities.
(d)	Adjustment to exclude severance charges and adjustments to previously recorded severance reserves.
(e)	Adjustment to exclude certain costs associated with Exelon’s merger with PSEG which was terminated in September 2006.
(f)	Adjustment to exclude the impairment of ComEd’s goodwill.
(g)	Adjustment to exclude the 2005 financial impact of Generation’s investment in Sithe.
(h)	Adjustment for the cumulative effect of adopting FIN 47.
(i)	Adjustment to exclude the 2004 financial impact of Boston Generating.
(j)	Adjustment for a settlement gain related to the storage of spent nuclear fuel.
(k)	Adjustment to exclude the losses associated with debt retirements at ComEd.
(l)	Adjustments for impairments and other charges associated with Generation’s investment in Sithe.
(m)	Adjustment for the cumulative effect of adopting FIN 46-R.

7

Exelon Corporation — Reconciliation of Adjusted (non-GAAP) Operating Earnings
to GAAP Consolidated Statements of Income (unaudited)

	Twelve Months Ended December 31, 2005									Twelve Months Ended December 31, 2004
(unaudited, in millions,							Adjusted									Adjusted
except per share date)	GAAP(a)			Adjustments			Non-GAAP			GAAP(a)			Adjustments			Non-GAAP
Earnings per average common share
Basic:
Income from continuing operations	$	1.42		$	1.73		$	3.15		$	2.83		$	0.03		$	2.86
Income (loss) from discontinued operations		0.02			(0.03	)		(0.01	)		(0.04	)		0.02			(0.02	)
Income before cumulative effect of changes in accounting principles		1.44			1.70			3.14			2.79			0.05			2.84
Cumulative effect of changes in accounting principles, net of income taxes		(0.06	)		0.06			—			0.03			(0.05	)		(0.02	)
Net income	$	1.38		$	1.76		$	3.14		$	2.82		$	—		$	2.82
Diluted:
Income from continuing operations	$	1.40		$	1.71		$	3.11		$	2.79		$	0.03		$	2.82
Income (loss) from discontinued operations		0.02			(0.03	)		(0.01	)		(0.04	)		0.02			(0.02	)
Income before cumulative effect of changes in accounting principles		1.42			1.68			3.10			2.75			0.05			2.80
Cumulative effect of changes in accounting principles, net of income taxes		(0.06	)		0.06			—			0.03			(0.05	)		(0.02	)
Net income	$	1.36		$	1.74		$	3.10		$	2.78		$	—		$	2.78
Average common shares outstanding
Basic		669						669			661						661
Diluted		676						676			669						669

(a) Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

8

Commonwealth Edison Company — Reconciliation of Adjusted (non-GAAP) Operating Earnings
to GAAP Consolidated Statements of Income (unaudited)

	Twelve Months Ended December 31, 2005									Twelve Months Ended December 31, 2004
							Adjusted									Adjusted
(unaudited, in millions)	GAAP(a)			Adjustments			Non-GAAP			GAAP(a)			Adjustments			Non-GAAP
Operating revenues	$	6,264		$	—		$	6,264		$	5,803		$	—		$	5,803
Operating expenses
Purchased power		3,520			—			3,520			2,588			—			2,588
Operating and maintenance		833			6	(b),(c)		839			897			(37	)(b)		860
Impairment of goodwill		1,207			(1,207	)(d)		—			—			—			—
Depreciation and amortization		413			—			413			410			—			410
Taxes other than income		303			—			303			291			—			291
Total operating expenses		6,276			(1,201	)		5,075			4,186			(37	)		4,149
Operating income (loss)		(12	)		1,201			1,189			1,617			37			1,654
Other income and deductions
Interest expense		(295	)		—			(295	)		(369	)		—			(369	)
Equity in losses of unconsolidated affiliates		(14	)		—			(14	)		(19	)		—			(19	)
Other, net		8			—			8			(96	)		130	(f)		34
Total other income and deductions		(301	)		—			(301	)		(484	)		130			(354	)
Income (loss) before income taxes		(313	)		1,201			888			1,133			167			1,300
Income taxes		363			(2	)(b),(c)		361			457			67	(b),(f)		524
Income (loss) before cumulative effect of a change in accounting principle		(676	)		1,203			527			676			100			776
Cumulative effect of a change in accounting principle, net of income taxes		(9	)		9	(e)		—			—			—			—
Net income (loss)	$	(685	)	$	1,212		$	527		$	676		$	100		$	776

(a) Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b) Adjustment to exclude severance charges and adjustments to previously recorded severance reserves.

(c) Adjustment to exclude certain costs associated with Exelon’s merger with PSEG which was terminated in September 2006.

(d) Adjustment to exclude the impairment of ComEd’s goodwill.

(e) Adjustment for the cumulative effect of adopting FIN 47.

(f) Adjustment to exclude the losses associated with debt retirements at ComEd.

9

PECO Energy Company — Reconciliation of Adjusted (non-GAAP) Operating Earnings
to GAAP Consolidated Statements of Income (unaudited)

	Twelve Months Ended December 31, 2005									Twelve Months Ended December 31, 2004
							Adjusted									Adjusted
(unaudited, in millions)	GAAP(a)			Adjustments			Non-GAAP			GAAP(a)			Adjustments			Non-GAAP
Operating revenues	$	4,910		$	—		$	4,910		$	4,487		$	—		$	4,487
Operating expenses
Purchased power		1,918			—			1,918			1,644			—			1,644
Fuel		597			—			597			528			—			528
Operating and maintenance		549			(7	)(b),(d)		542			547			(15	)(d)		532
Depreciation and amortization		566			(13	)(b)		553			518			—			518
Taxes other than income		231			—			231			236			—			236
Total operating expenses		3,861			(20	)		3,841			3,473			(15	)		3,458
Operating income		1,049			20			1,069			1,014			15			1,029
Other income and deductions
Interest expense		(280	)		—			(280	)		(303	)		—			(303	)
Equity in losses of unconsolidated affiliates		(16	)		—			(16	)		(25	)		—			(25	)
Other, net		14			—			14			18			—			18
Total other income and deductions		(282	)		—			(282	)		(310	)		—			(310	)
Income before income taxes		767			20			787			704			15			719
Income taxes		247			7	(b),(d)		254			249			6	(d)		255
Income before cumulative effect of a change in accounting principle		520			13			533			455			9			464
Cumulative effect of a change in accounting principle, net of income taxes		(3	)		3	(c)		—			—			—			—
Net income	$	517		$	16		$	533		$	455		$	9		$	464

(a) Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b) Adjustment to exclude certain costs associated with Exelon’s merger with PSEG which was terminated in September 2006.

(c) Adjustment for the cumulative effect of adopting FIN 47.

(d) Adjustment to exclude severance charges.

10

Exelon Generation Company — Reconciliation of Adjusted (non-GAAP) Operating
Earnings to GAAP Consolidated Statements of Income (unaudited)

	Twelve Months Ended December 31, 2005									Twelve Months Ended December 31, 2004
							Adjusted									Adjusted
(unaudited, in millions)	GAAP(a)			Adjustments			Non-GAAP			GAAP(a)			Adjustments			Non-GAAP
Operating revenues	$	9,046		$	—		$	9,046		$	7,703		$	(248	)(g)	$	7,455
Operating expenses
Purchased power		2,569			(12	)(b)		2,557			2,307			20	(b),(g)		2,327
Fuel		1,913			(4	)(b)		1,909			1,704			(249	)(b),(g)		1,455
Operating and maintenance		2,288			(9	)(c),(f)		2,279			2,201			(46	)(f),(g),(h)		2,155
Depreciation and amortization		254			—			254			286			(4	)(g)		282
Taxes other than income		170			—			170			166			(9	)(g)		157
Total operating expenses		7,194			(25	)		7,169			6,664			(288	)		6,376
Operating income		1,852			25			1,877			1,039			40			1,079
Other income and deductions
Interest expense		(128	)		—			(128	)		(103	)		5	(g)		(98	)
Equity in losses of unconsolidated affiliates		(1	)		—			(1	)		(14	)		—			(14	)
Other, net		95			—			95			130			(90	)(g)		40
Total other income and deductions		(34	)		—			(34	)		13			(85	)		(72	)
Income from continuing operations before income taxes and minority interest		1,818			25			1,843			1,052			(45	)		1,007
Income taxes		709			10	(b),(c),(f)		719			401			(19	)(b),(f),(g),(h)		382
Income from continuing operations before minority interest		1,109			15			1,124			651			(26	)		625
Minority interest		—			—			—			6			—			6
Income from continuing operations		1,109			15			1,124			657			(26	)		631
Income (loss) from discontinued operations		19			(18	)(d)		1			(16	)		11	(i)		(5	)
Income before cumulative effect of a change in accounting principle		1,128			(3	)		1,125			641			(15	)		626
Cumulative effect of a change in accounting principle, net of income taxes		(30	)		30	(e)		—			32			(32	)(j)		—
Net income	$	1,098		$	27		$	1,125		$	673		$	(47	)	$	626

(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).
(b)	Adjustment to exclude the mark-to-market impact of Generation’s non-trading activities, including for fuel expense $1 million and $4 million in amortization of the premium on a hedge on tax credits generated from the operation of synthetic fuel-producing facilities for the three and twelve months ended December 31, 2005, respectively.
(c)	Adjustment to exclude certain costs associated with Exelon’s merger with PSEG which was terminated in September 2006.
(d)	Adjustment to exclude the 2005 financial impact of Generation’s investment in Sithe.
(e)	Adjustment for the cumulative effect of adopting FIN 47.
(f)	Adjustment to exclude severance charges.
(g)	Adjustment to exclude the 2004 financial impact of Boston Generating.
(h)	Adjustment for a settlement gain related to the storage of spent nuclear fuel.
(i)	Adjustments for impairments and other charges associated with Generation’s investment in Sithe.
(j)	Adjustment for the cumulative effect of adopting FIN 46-R.

11

Exelon and Operating Companies — Capital Structure and Capitalization Ratios

(at December 31)	2005							2004						2003
	(in millions)			(in percent)		(in percent)(a)		(in millions)		(in percent)		(in percent)(a)		(in millions)		(in percent)		(in percent)(a)
Exelon (consolidated)
Total Debt	$	13,964			60.3		52.1	$	13,551		58.6		47.8	$	15,760		62.4		51.8
Preferred Securities of Subsidiaries		87			0.4		0.5		87		0.4		0.5		87		0.3		0.4
Total Shareholders’ Equity		9,125			39.4		47.5		9,489		41.0		51.8		9,423		37.3		47.7
Total Capitalization		23,176							23,127						25,270
Transition Debt	$	3,963						$	4,797					$	5,525
ComEd
Total Debt	$	4,176			39.5		33.3	$	4,875		42.0		34.4	$	6,440		50.4		42.9
Total Shareholders’ Equity		6,396			60.5		66.7		6,740		58.0		65.6		6,342		49.6		57.1
Total Capitalization		10,572							11,615						12,782
Transition Debt	$	987	(b)					$	1,341					$	1,676
PECO Energy
Total Debt	$	4,562			72.8		48.2	$	4,839		77.6		49.7	$	5,438		84.3		61.0
Total Shareholders’ Equity		1,704			27.2		51.8		1,398		22.4		50.3		1,016		15.7		39.0
Total Capitalization		6,266							6,237						6,454
Transition Debt	$	2,975	(c)					$	3,456					$	3,849
Exelon Generation
Total Debt	$	2,203			35.6			$	2,913		48.9			$	3,223		52.2
Total Members’ Equity		3,980			64.4				3,039		51.1				2,956		47.8
Total Capitalization	$	6,183						$	5,952					$	6,179

(a)	Excluding ComEd and PECO transition debt
(b)	ComEd transition debt maturities (in millions): 2006 — $307, 2007 — $340, 2008 — $340.
(c)	PECO transition debt maturities (in millions): 2006 — $199, 2007 — $645, 2008 — $625, 2009 - $700, 2010 — $806.
	Note: Numbers may not add due to rounding.

Credit Ratings as of October 31, 2006

	Moody’s Investors		Standard & Poor’s
	Service(a)		Corporation(b)		Fitch Ratings(c)
Exelon Corporation
Senior Unsecured Debt	Baa2		BBB		BBB+
Commercial Paper		P2		A2		F2
ComEd
Senior Secured Debt	Baa2		BBB		BBB+
Commercial Paper		P3		A3		F2
PECO Energy
Senior Secured Debt		A2		A-		A
Commercial Paper		P1		A2		F1
Exelon Generation
Senior Unsecured Debt	Baa1		BBB+		BBB+
Commercial Paper		P2		A2		F2

(a)	ComEd ratings under review for possible downgrade; Exelon, PECO and Generation ratings outlooks are stable.
(b)	Exelon, ComEd, PECO and Generation ratings are on CreditWatch with negative implications.
(c)	ComEd ratings outlook is negative; Exelon, PECO and Generation ratings outlooks are stable.

12

Exelon Corporation — Long-Term Debt Outstanding as of September 30, 2006

	Interest			Date		Maturity		Total Debt			Current		Long-Term
Series	Rate			Issued		Date		Outstanding			Portion		Debt
(in millions)
Senior Notes Payable
2005 Senior Notes Payable		4.45	%		6/9/05		6/15/10	$	400		$	0	$	400
2005 Senior Notes Payable		4.90	%		6/9/05		6/15/15		800			0		800
2005 Senior Notes Payable		5.625	%		6/9/05		6/15/35		500			0		500
2001 Senior Notes Payable		6.75	%		5/8/01		5/1/11		500			0		500
Total Senior Notes Payable								$	2,200		$	0	$	2,200
Unamortized Debt Discount								$	(3	)	$	0	$	(3	)
Total Long-term Debt								$	2,197		$	0	$	2,197

Maturities
2006	$	0
2007		0
2008		0
2009		0
2010	$	400

Exelon Generation — Long-Term Debt Outstanding as of September 30, 2006

	Interest			Date		Maturity		Total Debt			Current		Long-Term
Series	Rate			Issued		Date		Outstanding			Portion		Debt
(in millions)
Senior Notes
2001 Senior Unsecured Notes		6.95	%		6/14/01		6/15/11	$	700		$	0	$	700
2003 Senior Unsecured Notes		5.35	%		12/16/03		1/15/14		500			0		500
Total Senior Unsecured Notes								$	1,200		$	0	$	1,200
Unsecured Pollution Control Notes
Montgomery Co. 2001 Ser. B	var. rate				9/5/01		10/1/30		69			0		69
Delaware Co. 2001 Ser. A	var. rate				4/25/01		4/1/21		39			0		39
Montgomery Co. 2001 Ser. A	var. rate				4/25/01		10/1/34		13			0		13
Delaware Co. 1993 Ser. A	var. rate				8/24/93		8/1/16		24			0		24
Salem Co. 1993 Ser. A	var. rate				9/9/93		3/1/25		23			0		23
Montgomery Co. 1994 Ser. A	var. rate				2/14/95		6/1/29		83			0		83
Montgomery Co. 1994 Ser. B	var. rate				7/2/95		6/1/29		13			0		13
York County 1993 Ser. A	var. rate				8/24/93		8/1/16		18			0		18
Montgomery Co. 1996 Ser. A	var. rate				3/27/96		3/1/34		34			0		34
Montgomery Co. 2002 Ser. A	var. rate				7/24/02		12/1/29		30			0		30
Indiana Co. 2003 A	var. rate				6/3/03		6/1/27		17			0		17
Delaware Co. 1999 Ser. A	var. rate				10/1/04		4/1/21		51			0		51
Montgomery Co. 1999 Ser. A	var. rate				10/1/04		10/1/30		92			0		92
Montgomery Co. 1999 Ser. B	var. rate				10/1/04		10/1/34		14			0		14
Total Unsec. Pollution Control Notes								$	520		$	0	$	520
AmerGen Notes Payable -
Oyster Creek		6.33	%				8/8/09	$	29		$	10	$	19
Capital Leases								$	44		$	2	$	42
Unamortized Debt Discount								$	(3	)	$	0	$	(3	)
Total Long-Term Debt								$	1,790		$	12	$	1,778

Maturities
2006	$	12
2007		12
2008		12
2009		11
2010	$	2

13

ComEd — Long-Term Debt Outstanding as of September 30, 2006

	Interest			Date		Maturity		Total Debt			Current		Long-Term
Series	Rate			Issued		Date		Outstanding			Portion		Debt
(in millions)
First Mortgage Bonds
76		8.25	%		10/1/91		10/1/06	$	95		$	95	$	0
78		8.375	%		10/15/91		10/15/06		31			31		0
Pollution Control-1996A		4.40	%		6/27/96		12/1/06		110			110		0
Pollution Control-1996B		4.40	%		6/27/96		12/1/06		89			89		0
99		3.70	%		1/22/03		2/1/08		295			0		295
83		8.00	%		5/15/92		5/15/08		120			0		120
Pollution Control-1994B		5.70	%		1/15/94		1/15/09		16			0		16
102		4.74	%		8/25/03		8/15/10		212			0		212
98		6.15	%		3/13/02		3/15/12		450			0		450
92		7.625	%		4/15/93		4/15/13		125			0		125
IL Dev. Fin. Authority - 2002 A	Variable				6/4/02		4/15/13		100			0		100
94		7.50	%		7/1/93		7/1/13		127			0		127
IL Dev. Fin. Authority - 2003 D	Variable				12/23/03		1/15/14		20			0		20
Pollution Control-1994C		5.85	%		1/15/94		1/15/14		17			0		17
101		4.70	%		4/7/03		4/15/15		260			0		260
104		5.95	%		8/28/06		8/15/16		300			0		300
IL Fin. Authority - 2005	Variable				3/17/05		3/1/17		91			0		91
IL Dev. Fin. Authority - 2003 A	Variable				5/8/03		5/15/17		40			0		40
IL Dev. Fin. Authority - 2003 B	Variable				9/24/03		11/1/19		42			0		42
IL Dev. Fin. Authority - 2003 C	Variable				11/19/03		3/1/20		50			0		50
100		5.875	%		1/22/03		2/1/33		254			0		254
103		5.90	%		3/6/06		3/15/36		325			0		325
Total First Mortgage Bonds								$	3,169		$	325	$	2,844
Sinking Fund Debentures
Sinking Fund Debenture		3.875	%		1/1/58		1/1/08		2			1		1
Sinking Fund Debenture		4.625	%		1/1/59		1/1/09		2			1		1
Sinking Fund Debenture		4.75	%		12/1/61		12/1/11		4			1		3
Total Sinking Fund Debentures								$	8		$	3	$	5
Notes Payable
Notes Payable		7.625	%		1/9/97		1/15/07		145			145		0
Notes Payable		6.95	%		7/16/98		7/15/18		140			0		140
Total Notes Payable								$	285		$	145	$	140
Long-Term Debt To Financing Trusts
Class A-6 Transitional Funding Trust Notes, Series 1998		5.63	%		12/16/98		6/25/07		216			216		0
Class A-7 Transitional Funding Trust Notes, Series 1998		5.74	%		12/16/98		12/25/08		510			84		426
Subordinated Debentures to ComEd Financing II		8.50	%		1/24/97		1/15/27		155			0		155
Subordinated Debentures to ComEd Financing III		6.35	%		3/17/03		3/15/33		206			0		206
Total Long-Term Debt to Financing Trusts								$	1,087		$	300	$	787
Unamortized Debt Discount								$	(18	)	$	0	$	(18	)
Total Long-Term Debt								$	4,531		$	773	$	3,758

Maturities
2006	$	325
2007		485
2008		757
2009		17
2010	$	212

14

PECO Energy — Long-Term Debt Outstanding as of September 30, 2006

	Interest			Date		Maturity		Total Debt			Current		Long-Term
Series	Rate			Issued		Date		Outstanding			Portion		Debt
(in millions)
First Mortgage Bonds
FMB		5.90	%		4/23/04		5/1/34	$	75		$	0	$	75
FMB		3.50	%		4/28/03		5/1/08		450			0		450
FMB		5.95	%		11/1/01		11/1/11		250			0		250
FMB		4.75	%		9/23/02		10/1/12		225			0		225
FMB		5.95	%		9/25/06		10/1/36		300			0		300
Total First Mortgage Bonds								$	1,300		$	0	$	1,300
Mortgage-Backed Pollution Control Notes
Delaware Co. 1988 Ser. A	var. rate				4/1/93		12/1/12		50			0		50
Delaware Co. 1988 Ser. B	var. rate				4/1/93		12/1/12		50			0		50
Delaware Co. 1988 Ser. C	var. rate				4/1/93		12/1/12		50			0		50
Salem Co. 1988 Ser. A	var. rate				4/1/93		12/1/12		4			0		4
Total Mortgage-Backed Pollution Control Notes								$	154		$	0	$	154
Notes Payable — Accounts
Receivable Agreement	variable						11/12/10	$	37		$	0	$	37
Long-Term Debt to PETT(a) and Other Financing Trusts
1999 A-6		6.05	%		3/26/99		3/1/07		92			92		0
1999 A-7		6.13	%		3/26/99		9/1/08		897			322		575
2000 A-3		7.625	%		5/2/00		3/1/09		399			0		399
2000 A-4		7.65	%		5/2/00		9/1/09		351			0		351
2001 A-1		6.52	%		3/1/01		9/1/10		806			0		806
PECO Energy Capital Trust III		7.38	%		4/6/98		4/6/28		81			0		81
PECO Energy Capital Trust IV		5.75	%		6/24/03		6/15/33		103			0		103
Total Long-Term Debt to PETT and Other Financing Trusts								$	2,729		$	414	$	2,315
Unamortized Debt Discount								$	(2	)	$	0	$	(2	)
Total Long-Term Debt								$	4,218		$	414	$	3,804

(a) PETT = PECO Energy Transition Trust

Maturities
2006	$	0
2007		645
2008		1,075
2009		700
2010	$	836

15

Exelon Service Area and Selected Generating Assets*

Illinois
A Exelon Corporate HQ
A ComEd HQ
B Exelon Nuclear HQ
1 Braidwood (N)
2 Byron (N)
3 Clinton (N)
4 Dresden (N)
5 LaSalle (N)
6 Quad Cities (N)
7 Southeast Chicago (F)

Maine
8 Wyman (F)

Maryland
9 Conowingo (R)

Massachusetts
10 Framingham (F)
11 New Boston (F)
12 West Medway (F)

New Jersey
13 Oyster Creek (N)
14 Salem (N)

Pennsylvania
C Exelon Power Team HQ
C Exelon Power HQ
C Exelon Generation HQ
D PECO HQ
15 Conemaugh (F)
16 Cromby (F)
17 Eddystone (F)
18 Fairless Hills (R)
19 Keystone (F)
20 Limerick (N)
21 Muddy Run (R)
22 Peach Bottom (N)
23 Schuylkill (F)
24 Three Mile Island (N)

Texas
25 Handley (F)
26 LaPorte (F)
27 Mountain Creek (F)

2005 Exelon Generation — Ownership Equity

	Output Mix in			Capacity in
	Megawatt Hours (MWh)			Megawatts (MW)
Nuclear		90	%		67	%
Coal		6	%		6	%
Oil		1	%		8	%
Gas		1	%		12	%
Renewables		2	%		7	%

* Map does not show 8 sites in the Philadelphia area where Exelon has peaking combustion turbines.

16

ComEd

Electric Sales Statistics and Revenue Detail

Full service reflects deliveries to customers taking electric service under tariffed rates. The power purchase option (PPO) allows the purchase of electricity from ComEd at market-based prices. Delivery only service reflects customers electing to receive generation service from an alternative supplier. Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

	2005		2004		2003
Retail Deliveries (in GWhs)
Full service
Residential		30,042		26,463		26,206
Small Commercial & Industrial		21,378		21,662		23,334
Large Commercial & Industrial		7,904		6,913		6,955
Public Authorities & Electric Railroads		2,133		1,893		2,297
Total Full Service		61,457		56,931		58,792
PPO
Small Commercial & Industrial		5,591		4,110		3,912
Large Commercial & Industrial		6,004		5,377		5,677
Total PPO		11,595		9,487		9,589
Delivery Only
Small Commercial & Industrial		5,677		6,305		5,210
Large Commercial & Industrial		13,633		14,634		12,110
Total Delivery Only		19,310		20,939		17,320
Total Retail Deliveries		92,362		87,357		85,701
Electric Revenue (in millions)
Full Service
Residential	$	2,584	$	2,295	$	2,272
Small Commercial & Industrial		1,671		1,649		1,720
Large Commercial & Industrial		408		380		413
Public Authorities & Electric Railroads		132		126		153
Total Full Service		4,795		4,450		4,558
PPO
Small Commercial & Industrial		385		274		256
Large Commercial & Industrial		345		304		312
Total PPO		730		578		568
Delivery Only
Small Commercial & Industrial		95		128		132
Large Commercial & Industrial		156		204		216
Total Delivery Only		251		332		348
Total Electric Retail Revenues		5,776		5,360		5,474
Wholesale and Miscellaneous Revenue		488		443		340
Total Operating Revenues	$	6,264	$	5,803	$	5,814
Electric Revenue ($ / MWh)
Full Service
Residential	$	86.01	$	86.72	$	86.70
Small Commercial & Industrial		78.16		76.12		73.71
Large Commercial & Industrial		51.62		54.97		59.38
Public Authorities & Electric Railroads		61.88		66.56		66.61
Total Full Service		78.02		78.16		77.53
PPO
Small Commercial & Industrial		68.86		66.67		65.44
Large Commercial & Industrial		57.46		56.54		54.96
Total PPO		62.96		60.93		59.23
Delivery Only
Small Commercial & Industrial		16.73		20.30		25.34
Large Commercial & Industrial		11.44		13.94		17.84
Total Delivery Only		13.00		15.86		20.09
Total Electric Retail Revenues	$	62.54	$	61.36	$	63.87

17

ComEd

Customers at Year End

	2005		2004		2003
Retail Delivery Customers
Full service
Residential		3,358,596		3,330,778		3,294,477
Small Commercial & Industrial		324,984		321,994		311,840
Large Commercial & Industrial		643		490		439
Public Authorities & Electric Railroads		1,293		1,267		11,489
Street & Highway Lighting		3,933		3,824		3,047
Wholesale		4		4		4
Total Full Service Customers		3,689,453		3,658,357		3,621,296
PPO
Small Commercial & Industrial		15,078		9,413		6,993
Large Commercial & Industrial		614		598		327
Public Authorities		0		0		992
Street & Highway Lighting		1		1		1
Total PPO Customers		15,693		10,012		8,313
Delivery Only
Small Commercial & Industrial		4,954		11,249		9,864
Large Commercial & Industrial		629		900		764
Public Authorities		0		0		1,388
Total Delivery Only		5,583		12,149		12,016
Total Retail Delivery Customers		3,710,729		3,680,518		3,641,625

Heating and Cooling Degree Days

	2005		2004		2003
Heating Degree Days (normal=6,498)		6,083		6,053		6,447
Cooling Degree Days (normal=830)		1,166		615		695

Peak System Load

	2005		2004		2003
Summer
Highest Peak Load (MW)		20,690		19,686		22,054
Winter
Highest Peak Load (MW)		16,081		15,222		14,812

18

PECO

Electric Sales Statistics and Revenue Detail

Full service reflects deliveries to customers taking electric service under tariffed rates. Delivery only service reflects customers electing to receive generation service from an alternative supplier. Miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

	2005		2004		2003
Retail Deliveries (in GWhs)
Full Service
Residential		13,135		10,349		11,358
Small Commercial & Industrial		7,263		6,728		6,624
Large Commercial & Industrial		15,205		14,908		14,739
Public Authorities & Electric Railroads		962		914		897
Total Full Service		36,565		32,899		33,618
Delivery Only
Residential		334		2,158		900
Small Commercial & Industrial		1,257		1,687		1,455
Large Commercial & Industrial		503		760		780
Total Delivery Only		2,094		4,605		3,135
Total Retail Deliveries		38,659		37,504		36,753
Electric Revenue (in millions)
Full Service
Residential	$	1,705	$	1,317	$	1,444
Small Commercial & Industrial		818		756		753
Large Commercial & Industrial		1,173		1,113		1,090
Public Authorities & Electric Railroads		84		80		80
Total Full Service		3,780		3,266		3,367
Delivery Only
Residential		25		164		65
Small Commercial & Industrial		63		86		75
Large Commercial & Industrial		13		20		21
Total Delivery Only		101		270		161
Total Electric Retail Revenues		3,881		3,536		3,528
Miscellaneous Revenue		212		203		215
Total Operating Revenues	$	4,093	$	3,739	$	3,743
Electric Revenue ($ / MWh)
Full Service
Residential	$	129.81	$	127.26	$	127.14
Small Commercial & Industrial		112.63		112.37		113.68
Large Commercial & Industrial		77.15		74.66		73.95
Public Authorities & Electric Railroads		87.32		87.53		89.19
Total Full Service		103.38		99.27		100.15
Delivery Only
Residential		74.85		76.00		72.22
Small Commercial & Industrial		50.12		50.98		51.55
Large Commercial & Industrial		25.84		26.32		26.92
Total Delivery Only		48.23		58.63		51.36
Total Electric Retail Revenues	$	100.39	$	94.28	$	95.99

19

PECO

Customers at Year End

	2005		2004		2003
Retail Delivery Customers
Full service
Residential		1,365,145		1,156,175		1,141,660
Small Commercial & Industrial		205,502		189,762		169,133
Large Commercial & Industrial		2,980		2,863		2,985
Public Authorities & Electric Railroads		1,209		1,207		1,187
Total Full Service Customers		1,574,836		1,350,007		1,314,965
Delivery Only
Residential		22,496		223,694		233,060
Small Commercial & Industrial		38,928		55,748		77,409
Large Commercial & Industrial		129		257		135
Total Delivery Only Customers		61,553		279,699		310,604
Total Retail Delivery Customers		1,636,389		1,629,706		1,625,569

Heating and Cooling Degree Days

	2005		2004		2003
Heating Degree Days (normal=4,787)		4,758		4,646		4,921
Cooling Degree Days (normal=1,235)		1,539		1,272		1,277

Peak System Load

	2005		2004		2003
Summer
Highest Peak Load (MW)		8,626		7,567		7,638
Winter
Highest Peak Load (MW)		6,550		6,838		6,346

20

PECO

Gas Sales Statistics, Revenue and Customer Detail

	2005		2004		2003
Deliveries to Customers (in mmcf)
Retail Sales		59,751		59,949		61,858
Transportation		25,310		27,148		26,404
Total Retail Deliveries		85,061		87,097		88,262
Gas Revenue (in millions)
Retail Sales	$	783	$	702	$	609
Transportation		16		18		18
Resales and Other		18		28		18
Total Gas Revenue	$	817	$	748	$	645
Gas Customers at Year End
		2005		2004		2003
Customers
Residential		430,753		423,858		416,568
Small Commercial & Industrial		40,293		39,803		39,202
Large Commercial & Industrial		129		127		124
Transportation		561		585		586
Total Customers		471,736		464,373		456,480
Gas Maximum Day Sendout
		2005		2004		2003
Winter
Maximum Day Sendout (in thousand cubic feet (mcf))		712,704		699,494		696,904

21

Exelon Generation — Generating Resources

Sources of Electric Supply

(GWhs)	2005		2004		2003
Nuclear units(a)		137,936		136,621		117,502
Purchases — non-trading portfolio(b)		42,623		48,968		83,692
Fossil and hydroelectric units		13,778		17,010		24,310
Total supply		194,337		202,599		225,504

(a)	Excludes AmerGen in 2003.
(b)	Includes purchase power agreements (PPAs) with AmerGen in 2003.

Type of Capacity

(MWs) At December 31,	2005		2004		2003
Owned generation assets
Nuclear		16,856		16,751		16,959
Fossil(a)		6,636		6,709		9,925
Hydroelectric		1,607		1,633		1,608
Owned generation assets		25,099		25,093		28,492
Long-term contracts		8,191		8,701		12,703
TEG and TEP(b)		230		230		—
Sithe(c)		—		663		549
Available resources		33,520		34,687		41,744
Under construction(c)		—		—		114
Total generating resources		33,520		34,687		41,858

(a)	In 2003, includes 3,145 MWs of capacity owned by Boston Generating, a subsidiary of Generation; ownership was transferred on May 25, 2004.
(b)	Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owns a 49.5% interest in two facilities in Mexico, each with a capacity of 230 MWs.
(c)	Based on Generation’s 50% ownership of Sithe Energies, Inc; Sithe investment was sold on January 31, 2005.

Long-Term Contracts

(At December 31, 2005)
ISO Region	Dispatch Type	Location	Seller	Fuel Type	Term	Capacity(MWs)
PJM	Base-load	Kincaid, IL	Kincaid Generation, LLC	Coal	1996 - 2011		1,108
SERC	Peaking	Franklin, GA	Tenaska Georgia	Oil/Gas	2001 - 2030		925
			Partners, LP
ERCOT	Base-load	Shiro, TX	Tenaska Frontier	Oil/Gas	2000 - 2020		830
			Partners, LLP
SPP	Peaking	Jenks, OK	Green Country	Oil/Gas	2002 - 2022		795
			Energy, LLC
PJM	Peaking	Elwood, IL	Elwood Energy, LLC	Oil/Gas	1999 - 2012		772
PJM	Peaking	Manhattan, IL	Lincoln Generating	Oil/Gas	2003 - 2011		664
			Facility, LLC
PJM	Peaking	Aurora, IL	Reliant Energy Wholesale	Oil/Gas	2003 - 2008		600
			Generation, LLC
PJM	Base-load	Hammond, IN	State Line Energy, LLC	Coal	1996 - 2011		515
ERCOT	Intermediate	Granbury, TX	Wolf Hollow, LP	Oil/Gas	2003 - 2023		350
PJM	Peaking	Lee County, IL	Duke Energy Trading Inc.	Oil/Gas	2002 - 2008		344
PJM	Peaking	East Dundee, IL	Dynegy Inc.	Oil/Gas	2001 - 2009		330
			(Rocky Road Plant)
PJM	Peaking	Crete, IL	DTE Energy Trading and	Oil/Gas	2003 - 2008		308
			Marketing, LLC
PJM	Peaking	University Park, IL	Constellation Energy	Oil/Gas	2002 - 2006		300
			Commodities Group I
ECAR	Base-load	Sullivan County, IN	Hoosier Energy	Coal	1997 - 2006		200
			Electric Rural Coop
PJM	Peaking	Morris, IL	Morris Cogeneration, LLC	Oil/Gas	2001 - 2011		100
PJM	Base-load	Kincaid, IL	Kincaid Generation, LLC	Coal	2001 - 2013		50
Total							8,191

ISO = Independent System Operator

22

Exelon Generation — Nuclear Generating Capacity

Exelon Nuclear Fleet^(a)

(At December 31, 2005)								Last Refueling
	Number	Plant	NSSS	Net Annual	Start	License		Completed	Refueling
Station	of Units	Type	Vendor	Mean Rating (MW)	Date	Expires	Ownership	by Unit	Cycle
Braidwood	2	PWR	W	1,194/1,166	1988	2026/2027	100%	May-06/May-05	18 mos.
Byron	2	PWR	W	1,183/1,153	1985/1987	2024/2026	100%	Oct-06/Oct-05	18 mos.
Clinton	1	BWR	GE	1,030	1987	2026	100%(b)	Feb-06	24 mos.
Dresden	2	BWR	GE	871/871	1970/1971	2029/2031	100%	Nov-05/Dec-04	24 mos.
LaSalle	2	BWR	GE	1,138/1,150	1984	2022/2023	100%	Mar-06/Mar-05	24 mos.
Limerick	2	BWR	GE	1,151/1,151	1986/1990	2024/2029	100%	Mar-06/Mar-05	24 mos.
Oyster Creek	1	BWR	GE	625	1969	2009(c)	100%(b)	Nov-04	24 mos.
Peach Bottom	2	BWR	GE	1,138/1,131	1974	2033/2034	50% Exelon,	Oct-06/Oct-05	24 mos.
							50% PSEG Nuclear
Quad Cities	2	BWR	GE	821/821	1973	2032/2032	75% Exelon,	Apr-05/Apr-06	24 mos.
							25% Mid-American
							Energy Holdings
TMI-1	1	PWR	B&W	837	1974	2014	100%(b)	Nov-05	24 mos.
Total	17			17,431			15,887 MW owned

(a)	Does not include Exelon Generation’s 42.59%, 969 MW, interest in Salem Units 1 and 2 (PWRs). Effective January 17, 2005, Generation began overseeing daily plant operations at the Salem and Hope Creek nuclear stations through an Operating Services Contract with PSEG Nuclear, LLC, which terminates on January 17, 2007 with a two- to three-year transition period. Last refueling outages: Salem Unit 1 completed November 2005 and Unit 2 began October 10, 2006.
(b)	Clinton, Oyster Creek and Three Mile Island are operated by AmerGen, wholly owned by Generation.
(c)	A December 2004 order permits Oyster Creek to operate beyond its license expiration if the NRC has not completed its renewal application review.
Notes:PWR = pressurized water reactor; BWR = boiling water reactor
	NSSS Vendor = Nuclear Steam Supply System Vendor

Nuclear Operating Data^(a)

	2005			2004			2003
Fleet capacity factor		93.5	%(b)		93.5	%		93.4	%
Fleet production cost per MWh	$	13.03		$	12.43		$	12.53

Refueling Outage Days^(a)

— Conducted nine refueling outages in 2005

— Average refueling outage duration in 2005: 24 days

— U.S. average refueling duration in 2005: ~38 days

Net Generation — 2005

— 130,160 GWhs, excluding Salem

— 137,936 GWhs, including Salem

(a) Excludes Salem; Salem’s capacity factor was 92% in 2005.

(b) vs. industry average of 90.2%.

23

Exelon Generation — Total Electric Generating Capacity

Owned net electric generating capacity by station at December 31, 2005; does not include properties held by equity method investments:

Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system, and consequently produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours, and consequently produce electricity by cycling on and off daily. Peaking units are plants that usually house low-efficiency, quick response steam units, gas turbines, diesels, or pumped-storage hydroelectric equipment normally used during the maximum load periods.

							Net
						Primary	Generation
		Number		Percent	Primary	Dispatch	Capacity(b)
Station	Location	of Units		Owned(a)	Fuel Type	Type	(MW)
Nuclear (c)
Braidwood	Braidwood, IL		2		Uranium	Base-load		2,360
Byron	Byron, IL		2		Uranium	Base-load		2,336
Clinton	Clinton, IL		1		Uranium	Base-load		1,030
Dresden	Morris, IL		2		Uranium	Base-load		1,742
LaSalle	Seneca, IL		2		Uranium	Base-load		2,288
Limerick	Limerick Twp., PA		2		Uranium	Base-load		2,302
Oyster Creek	Forked River, NJ		1		Uranium	Base-load		625
Peach Bottom	Peach Bottom Twp., PA		2	50.00	Uranium	Base-load		1,135	(d)
Quad Cities	Cordova, IL		2	75.00	Uranium	Base-load		1,232	(d)
Salem	Hancock’s Bridge, NJ		2	42.59	Uranium	Base-load		969	(d)
Three Mile Island	Londonderry Twp, PA		1		Uranium	Base-load		837
								16,856
Fossil (Steam Turbines)
Conemaugh	New Florence, PA		2	20.72	Coal	Base-load		352	(d)
Cromby 1	Phoenixville, PA		1		Coal	Base-load		144
Cromby 2	Phoenixville, PA		1		Oil/Gas	Intermediate		201
Eddystone 1, 2	Eddystone, PA		2		Coal	Base-load		588
Eddystone 3, 4	Eddystone, PA		2		Oil/Gas	Intermediate		760
Fairless Hills	Falls Twp, PA		2		Landfill Gas	Peaking		60
Handley 4, 5	Fort Worth, TX		2		Gas	Peaking		916
Handley 3	Fort Worth, TX		1		Gas	Intermediate		400
Keystone	Shelocta, PA		2	20.99	Coal	Base-load		358	(d)
Mountain Creek 2, 6, 7	Dallas, TX		3		Gas	Peaking		273
Mountain Creek 8	Dallas, TX		1		Gas	Intermediate		550
New Boston 1	South Boston, MA		1		Gas	Intermediate		353
Schuylkill	Philadelphia, PA		1		Oil	Peaking		166
Wyman	Yarmouth, ME		1	5.89	Oil	Intermediate		36	(d)
								5,157
Fossil (Combustion Turbines)
Chester	Chester, PA		3		Oil	Peaking		39
Croydon	Bristol Twp., PA		8		Oil	Peaking		384
Delaware	Philadelphia, PA		4		Oil	Peaking		56
Eddystone	Eddystone, PA		4		Oil	Peaking		60
Falls	Falls Twp., PA		3		Oil	Peaking		51
Framingham	Framingham, MA		3		Oil	Peaking		30
LaPorte	Laporte, TX		4		Gas	Peaking		160
Medway	West Medway, MA		3		Oil	Peaking		110
Moser	Lower Pottsgrove Twp., PA		3		Oil	Peaking		51
New Boston	South Boston, MA		1		Gas	Peaking		13
Pennsbury	Falls Twp., PA		2		Landfill Gas	Peaking		6
Richmond	Philadelphia, PA		2		Oil	Peaking		96
Salem	Hancock’s Bridge, NJ		1	42.59	Oil	Peaking		16	(d)
Schuylkill	Philadelphia, PA		2		Oil	Peaking		30
Southeast Chicago	Chicago, IL		8	72.00	Gas	Peaking		312	(e)
Southwark	Philadelphia, PA		4		Oil	Peaking		52
								1,466

24

Exelon Generation — Total Electric Generating Supply
(continued)

Owned net electric generating capacity by station at December 31, 2005; does not include properties held by equity method investments:

									Net
								Primary	Generation
		Number		Percent			Primary	Dispatch	Capacity(b)
Station	Location	of Units		Owned		(a)	Fuel Type	Type	(MW)
Fossil (Internal Combustion/Diesel)
Conemaugh	New Florence, PA		4		20.72		Oil	Peaking	2		(d)
Cromby	Phoenixville, PA		1				Oil	Peaking		3
Delaware	Philadelphia, PA		1				Oil	Peaking		3
Keystone	Shelocta, PA		4		20.99		Oil	Peaking	2		(d)
Schuylkill	Philadelphia, PA		1				Oil	Peaking		3
										13
Hydroelectric
Conowingo	Harford Co. MD		11				Hydroelectric	Base-load		536
Muddy Run	Lancaster, PA		8				Hydroelectric	Intermediate		1,071
										1,607
Total			126							25,099

(a)	100%, unless otherwise indicated.
(b)	For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating.
(c)	All nuclear stations are boiling water reactors except Braidwood, Byron, Salem and Three Mile Island, which are pressurized water reactors.
(d)	Net generation capacity is stated at proportionate ownership share.
(e)	Includes the total capacity of the Southeast Chicago Energy Project.

25

Fossil Emissions Reduction Summary

Owned generation as of December 31, 2005. Table does not include station auxiliary equipment, peaking combustion turbines or plants where Exelon owns less than 100 MW.

			Net Generation Available for Sale (MWh)
	Capacity
Fossil Station	(MW, Summer Rating)		2005		2004		2003
Conemaugh (New Florence, PA)		352		2,681,176		2,698,520		2,795,752
Units: 2 coal units (baseload).
Reduction Technology: SO2 Scrubbed.
Data reflects Exelon Generation’s 20.72% plant ownership
Cromby (Phoenixville, PA)		345		1,010,799		928,105		876,462
Units: 1 coal unit (baseload), 1 oil/gas steam unit (intermediate).
Reduction Technology: SO2 scrubber (Coal unit) and SNCR NOx
Delaware (Philadelphia, PA)		250		—		24,130		160,399
Units: 2 oil steam units (peaking, retired in 2004)
Reduction Technology: None
Eddystone (Eddystone, PA)		1,348		3,748,334		3,205,674		3,528,070
Units: 2 coal units (baseload), 2 oil/gas steam units (intermediate).
Reduction Technology: SO2 scrubbers (Coal units), SNCR NOx, and low NOx burners with separate overfire air.
Handley(a) (Ft. Worth, TX)		1,316		803,986		1,017,590		1,651,387
Units: 3 gas steam units (peaking/intermediate)
Reduction Technology: SCR NOx (Units 3,4, and 5)
Keystone (Shelocta, PA)		358		2,827,950		2,578,620		2,611,887
Units: 2 coal units (baseload)
Reduction Technology: SCR NOx
Data reflects Exelon Generation’s 20.99% plant ownership.
Mountain Creek(a) (Dallas, TX)		823		660,123		459,909		792,174
Units: 4 gas steam units (peaking/intermediate)
Reduction Technology: Induced flue gas recirculation (Units 6 and 7)
Reduction Technology: SCR NOx (Unit 8)
New Boston (South Boston, MA)		353		246,860		160,563		199,135
Units: 1 gas steam unit (intermediate)
Reduction Technology: None
Schuylkill (Philadelphia, PA)		166		129,260		70,782		41,724
Units: 1 oil steam unit (peaking)
Reduction Technology: None

(a) Handley Units 1 and 2 and Mountain Creek Unit 3 were removed from service in 2005. These units represented a combined 195 MW of capacity.

26

Fossil Emissions Reduction Summary

Emissions (tons)							Reduction Technology
											Low NOx
											burners with			Induced
							SO2		SNCR		separate			flue gas
Type	2005		2004		2003		Scrubbed		NOx		overfire air			recirculation
Conemaugh
SO2		1,487		1,493		1,528		X
NOx		4,074		4,091		4,456
CO2		2,612,601		2,556,113		2,666,915
Cromby
SO2		4,990		6,873		5,442	X (Coal Unit)
NOx		2,105		2,057		1,952				X
CO2		1,221,416		1,249,773		1,257,579
Delaware
SO2		—		71		501
	NOx			—		60		359
CO2		—		28,454		187,805
Eddystone
SO2		8,675		8,242		9,415	X (Coal Units)
NOx		6,378		5,276		5,975				X		X
CO2		4,617,722		4,172,765		4,794,725
Handley
SO2		3		4		9
NOx		56		206		830	X (Units 3,4,5)
CO2		654,284		825,199		1,396,256
Keystone
SO2		37,523		35,958		34,317
NOx		2,938		2,850		2,398				X
CO2		2,718,347		2,467,692		2,501,247
Mountain Creek
SO2		2		4		10
NOx		97		78		196			X (Unit 8)			X	(Units 6 and 7)
CO2		489,586		353,462		535,860
New Boston
SO2		1		1		2
NOx		132		93		101
CO2		163,798		110,507		128,496
Schuylkill
SO2		359		407		125
NOx		180		82		47
CO2		140,475		74,517		46,224

27

Exelon Generation — Electric Sales Statistics

	Twelve Months Ended December 31,
(in GWhs)	2005			2004			2003
Supply
Nuclear		137,936			136,621			117,502
Purchased Power — Generation(a)		42,623			48,968			83,692
Fossil and Hydro		13,778			17,010			24,310
Power Team Supply		194,337			202,599			225,504
Purchased Power — Other		878			585			659
Total Electric Supply Available for Sale		195,215			203,184			226,163
Less: Line Loss and Company Use		(10,368	)		(9,264	)		(9,034	)
Total Supply		184,847			193,920			217,129
Energy Sales
Retail Sales		137,348			130,945			127,758
Power Team Market Sales(a)		66,049			86,049			107,267
Interchange Sales and Sales to Other Utilities		2,854			2,470			2,556
		206,251			219,464			237,581
Less: Delivery Only Sales		(21,404	)		(25,544	)		(20,452	)
Total Energy Sales		184,847			193,920			217,129

(a)Purchased power and market sales do not include trading volume of 26,924 GWhs, 24,001 GWhs and 32,584 GWhs for the twelve months ended December 31, 2005, 2004 and 2003, respectively.

Exelon Generation — Power Team Marketing Statistics

	Twelve Months Ended December 31,
	2005		2004		2003
GWh Sales
ComEd		82,798		75,092		76,960
PECO		39,163		35,373		35,728
Market and Retail Sales		72,376		92,134		112,816
Total Sales(a)		194,337		202,599		225,504
Average Margin ($/MWh)
Average Realized Revenue
ComEd	$	37.50	$	30.66	$	40.10
PECO		42.64		40.91		31.26
Market and Retail Sales(b)		46.16		35.03		36.40
Total Sales — without trading		41.76		34.43		35.20
Average Purchased Power and Fuel Cost — without trading(c)	$	20.11	$	17.60	$	24.61
Average Margin — without trading(c)	$	21.65	$	16.83	$	10.59
Around-the-clock Market Prices ($/MWh)
PECO — PJM West Hub	$	60.92	$	42.34	$	38.02
ComEd — NIHUB		46.39		31.15		28.32

(a)	Total sales do not include trading volume of 26,924 GWhs, 24,001 GWhs and 32,584 GWhs for the twelve months ended December 31, 2005, 2004 and 2003, respectively.
(b)	Market and retail sales exclude revenues related to tolling agreements of $86 million, $97 million and $99 million for the twelve months ended December 31, 2005, 2004 and 2003, respectively.
(c)	Adjustments have been made to historical periods for consistency with current year presentation, including the exclusion of mark-to-market adjustments from operating earnings and the classification of Sithe’s and All Energy’s results as discontinued operations.

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Exelon Generation — Power Team Marketing Statistics by Quarter

	Three Months Ended
	September 30,		June 30,		March 31,		December 31,		September 30,		June 30,		March 31,		December 31,
	2006		2006		2006		2005		2005		2005		2005		2004
GWh Sales
ComEd		22,566		18,685		20,309		19,749		24,331		19,625		19,093		18,312
PECO		11,361		9,262		9,615		9,404		11,442		8,957		9,360		8,516
Market and Retail Sales		19,075		18,744		14,308		17,431		19,525		18,410		17,010		21,281
Total Sales(a)		53,002		46,691		44,232		46,584		55,298		46,992		45,463		48,109
Average Margin ($/MWh)
Average Realized Revenue
ComEd	$	39.31	$	35.80	$	37.22	$	32.56	$	39.87	$	38.47	$	38.60	$	39.81
PECO		47.71		46.32		43.27		42.32		44.84		42.20		40.71		26.54
Market and Retail Sales(b)		54.21		50.31		52.14		49.34		53.16		42.53		38.80		34.11
Total Sales — without trading		46.47		43.71		43.36		40.81		45.61		40.77		39.11		32.24
Average Purchased Power and Fuel Cost — without trading(c)	$	24.38	$	17.28	$	15.94	$	18.78	$	27.09	$	17.71	$	15.22	$	14.33
Average Margin - without trading(c)	$	22.09	$	26.43	$	27.42	$	22.03	$	18.52	$	23.06	$	23.89	$	17.91
Around-the-clock Market Prices ($/MWh)
PECO — PJM West Hub	$	58.15	$	48.07	$	56.42	$	73.87	$	75.33	$	47.30	$	47.18	$	38.84
ComEd — NIHUB		46.15		39.28		42.48		52.81		54.75		38.35		39.68		29.99

(a)	Total sales do not include trading volume of 8,909 GWhs, 7,769 GWhs, 6,985 GWhs, 8,756 GWhs, 6,757 GWhs, 5,660 GWhs, 5,751 GWhs and 6,432 GWhs for the three months ended September 30, 2006, June 30, 2006, March 31, 2006, December 31, 2005, September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004, respectively.
(b)	Market and retail sales exclude revenues related to tolling agreements of $52 million, $34 million, $52 million and $34 million for the three months ended September 30, 2006,June 30, 2006, September 30, 2005 and June 30, 2005, respectively.
(c)	Adjustments have been made to historical periods for consistency with current year presentation, including the exclusion of mark-to-market adjustments from operating earnings and the classification of Sithe’s and All Energy’s results as discontinued operations.

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