 Supplemental Information 2007 Exelon Investor Conference December 19, 2007 Exhibit 99.3 |
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 3 ’07E Earnings: $2,320 - $2,385M ’08E Earnings: $2,060 - $2,260M ’07 EPS: $3.45 - $3.55 ‘08 EPS: $3.15 - $3.45 Total Debt (1) : $1.8B Credit Rating (2) : BBB+ The Exelon Companies Nuclear, Fossil, Hydro & Renewable Generation Power Marketing ‘07E Operating Earnings: $2.8 - $2.9B ‘07 EPS Guidance: $4.15 - $4.30 ‘08E Operating Earnings: $2.6 - $2.9B ‘08 EPS Guidance: $4.00 - $4.40 Assets (1) : $44.3B Total Debt (1) : $13.0B Credit Rating (2) : BBB Note: All estimates represent adjusted (Non-GAAP) Operating Earnings and EPS. Exelon Generation, ComEd and PECO estimates represent expected contribution to Exelon’s operating earnings EPS (per Exelon share). Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (1) As of 12/31/06. (2) Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 12/14/07. Pennsylvania Utility Illinois Utility ’07E Earnings: $130 - $165M $435 - $470M ’08E Earnings: $220 - $260M $360 - $400M ’07 EPS: $0.20 - $0.25 $0.65 - $0.70 ’08 EPS: $0.35 - $0.40 $0.55 - $0.60 Total Debt (1) : $4.6B $4.2B Credit Ratings (2) : BBB A |
 4 Multi-Regional, Diverse Company Note: Megawatts based on Generation’s ownership as of 10/1/07, using annual mean ratings for nuclear units (excluding Salem) and summer ratings for Salem and the fossil and hydro units; capacity excludes New Boston Unit 1 and State Line PPA. Mid-Atlantic contracts include wind and cogeneration projects. Midwest Capacity Owned: 11,373 MW Contracted: 4,271 MW Total: 15,644 MW ERCOT/South Capacity Owned: 2,222 MW Contracted: 2,917 MW Total: 5,139 MW New England Capacity Owned: 181MW Total Capacity Owned: 24,746 MW Contracted: 7,524 MW Total: 32,270 MW Electricity Customers: 1.6M Gas Customers: 0.5M Electricity Customers: 3.8M Generating Plants Nuclear Hydro Coal/Oil/Gas Base-load Intermediate Peaker Mid-Atlantic Capacity Owned: 10,970 MW Contracted: 336 MW Total: 11,306 MW |
 5 Illinois Settlement • Continued ComEd membership in PJM • Competitive procurement for supply • Filed competitive declaration for 100 - 400 kW customers • Statute mandates cost recovery for purchased power • Reduced uncertainty around conditions for ICC approval for strategic transactions such as reorganizations or mergers • Immediate rate relief for customers • Provisions to help stabilize rates • Energy efficiency and demand response programs and renewable portfolio standards Protects Competitive Markets Protects Value of Generation Provides Strategic Flexibility Customer Focused • Eliminated the IL Attorney General’s challenges to the 2006 auction • Financial swap at market prices • No generation tax |
 6 $4,450 $2,740 $920 $700 Cash Flow from Operations (1) ($3,120) ($1,600) ($390) ($1,000) Capital Expenditures $1,220 $1,240 ($50) $300 Net Financing (excluding Dividend) (2) $2,550 $2,380 $480 $0 Cash available before Dividend ($1,310) Dividend (3) $1,240 Cash available after Dividend Exelon (1) ($ in Millions) 2008 Projected Sources and Uses of Cash (1) Cash Flow from Operations = Net cash flows provided by operating activities less net cash flows used in investing activities other than capital expenditures. (2) Net Financing (excluding Dividend) = Net cash flows used in financing activities excluding dividends paid on common and preferred stock. (3) Assumes 2008 Dividend of $2.00 per share. (4) Includes cash flow activity from Holding Company, eliminations, and other corporate entities. |
 7 3-4% $1,000 $1,060 2-3% $1,020 $1,030 1-2% $390 $350 2-3% $650 $620 Exelon (1) NM (2) NM (2) ~15% 2008-2012 CAGR $3,120 $870 $730 2008E $2,740 $720 $580 2007E Other Nuclear Fuel CapEx 2-3% 2-3% 2008-2012 CAGR $4,250 $2,620 2008E $4,090 $2,450 2007E Exelon (1) O&M Note: Reflects operating O&M data and excludes Decommissioning Trust Fund impact. (1) Includes eliminations and other corporate entities. (2) Due to varying capital investment for the period 2008-2012, the CAGR is not meaningful. ($ in Millions) O&M and CapEx Expectations ($ in Millions) |
 8 Industry Is Facing a Capital Investment Challenge Source: Cambridge Energy Research Associates Current Industry Market Cap ($B) ~$750B Generation for 230+ GWs Transmission Distribution $50B Conservation & Energy Efficiency $50B (excl. Carbon) Environmental Retrofits CapEx Spend Next 15 Years ($B) Investment required over the next 15 years exceeds the current market capitalization of the entire electric industry $300B $350B $150B ~$900B |
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 10 10 ComEd Transmission Case Settlement (1) ($ in millions) FERC Filing 3/1/07 Preliminary Order 6/5/07 Settlement Filing 10/5/07 (1) Total Revenue Requirement (in year 1) (2) $415 $387 $364 Revenue Requirement increase (in year 1) $146 $116 (3) $93 Rate Base (in year 1) $1,826 $1,744 $1,672 (4) Common Equity Ratio 58% 58% 58% (5) Return on Equity (ROE) (6) 12.20% 11.70% + 0.50% RTO adder 12.20% 11.70% + 0.50% RTO adder 11.50% 11.0% + 0.50% RTO adder Return on Rate Base (ROR) 9.87% 9.87% 9.40% Rate settlement establishes reasonable framework for timely recovery of transmission investment on an annual basis through formula rates (1) Subject to final FERC approval. (2) Included a request for project incentives of $16 million. (3) Rates effective 5/1/07, subject to refund. (4) Excludes pension asset; 6.51% debt return allowed in operating expenses. (5) Equity cap of 58% for 2 years, declining to 55% by 2011. (6) ROE is fixed and not subject to annual updating. RTO = Regional Transmission Organization (Docket Nos. ER07-583-000 & EL07-41-000) |
 11 11 Formula Transmission Rate Annual Update Process (1) • Annual filing by May 15th will update the current year revenue requirement and true-up prior year to actual: – Update current year – Estimate current year revenue requirement using updated costs based on prior year actual data per FERC Form 1 plus projected plant additions for the current calendar year – True-up prior year – Perform a true-up of the prior year’s rates by comparing prior year actual data per FERC Form 1 to the estimate used for that year; over/under-recoveries for the prior year are collected in the current year • Rates take effect on June 1st • Interested parties have 180 days to submit information requests and raise concerns; unresolved concerns go before FERC for resolution The combination of annual updating and true-up virtually eliminates regulatory lag (1) Subject to final FERC approval. |
 12 Revenue increase needed to recover significant distribution system investment and represents an important step in ComEd’s regulatory recovery plan (1) Based on 2006 test year, including pro forma capital additions through 3Q 2008; represents a $1,550 million increase from 2006 ICC order. (2) Includes increased depreciation expense associated with capital additions. (3) Requested cap structure does not include goodwill; ICC docket 05-0597 allowed 10.045% ROE, 42.86% equity ratio and 8.01% ROR (return on rate base). (4) Primarily includes increases in pension and other post-retirement benefits costs and effects of a reclassification of rental revenue of $20 million, which is offset in “Other adjustments”. (5) Includes taxes other than income, regulatory expenses, and reductions for other revenues and load growth. (6) Or approximately $359 million adjusted for normal weather. ComEd Delivery Service Rate Case Filing (Docket No. 07-566) $361 (6) Total ($2,049 revenue requirement) $(51) Other adjustments (5) $48 O&M expenses $99 Administrative & General expenses (4) $50 Capital Structure (3) : ROE - 10.75% / Common Equity - 45.11% / ROR - 8.55% $215 (2) Rate Base: $7,071 (1) Requested Revenue Requirement Increase $ in millions) |
 13 ComEd Delivery Service Rate Case – Schedule • Filed: October 17, 2007 • Staff & Intervenor Direct Testimony: February 11, 2008 • ComEd Rebuttal Testimony: March 12 • Staff & Intervenor Rebuttal Testimony: April 8 • ComEd Surrebuttal Testimony: April 21 • Hearings: April 28 - May 5 • Initial Briefs: May 29 • Reply Briefs: June 12 • Administrative Law Judge (ALJ) Order expected: July • Final Illinois Commerce Commission (ICC) Order expected: September 2008 |
 14 Financial Swap Agreement • Financial Swap Agreement between ComEd and Exelon Generation promotes price stability for residential and small business customers • Designed to dovetail with ComEd’s remaining auction contracts for energy, increasing in volume as the auction contracts expire – Will cover about 60% of the energy that ComEd’s residential and small business customers use • Includes ATC baseload energy only – Does not include capacity, ancillary services or congestion 3,000 $53.48 January 1, 2013 - May 31, 2013 3,000 $52.37 January 1, 2012 - December 31, 2012 3,000 $51.26 January 1, 2011 - December 31, 2011 3,000 $50.15 June 1, 2010 - December 31, 2010 2,000 $50.15 January 1, 2010 - May 31, 2010 2,000 $49.04 June 1, 2009 - December 31, 2009 1,000 $49.04 January 1, 2009 - May 31, 2009 1,000 $47.93 June 1, 2008 - December 31, 2008 Notional Quantity (MW) Fixed Price ($/MWH) Portion of Term |
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    16 Pennsylvania Snapshot • Governor Rendell proposed an Energy Independence Strategy (EIS) in February 2007 Aimed at reducing energy costs, increasing clean energy sources, reducing reliance on foreign fuels and expanding energy production in PA Funded through a systems benefit charge • Special legislation session on Energy Policy began September 17 th Runs through mid-December Current State of Play • Legislators concerned with cost of funding Governor's initiatives, no new taxes • Rate freeze and/or generation tax legislation being considered • Industry coalition working together to develop a comprehensive package Position of Stakeholders • Stakeholder outreach • Working with industry coalition • Negotiating legislative proposals with Administration and legislative leadership Smart meters and real time pricing Energy efficiency and demand side management programs Procurement Contracts for large industrials Utilities owning generation Rate increase deferral/phase-in • Participating directly or through industry associations in legislative hearings and informational meetings • Evaluating alternative proposals PECO Actions |
 17 Key Themes of Legislative Proposals Competitive procurement process utilizing auctions, RFPs, spot purchases and bilateral contracts Full and current cost recovery for default service provider (DSP) DSP must offer residential and small commercial customers a rate that changes no more frequently than annually with reconciliation for under or over-recovery Must file a rate phase-in plan for all customers with the option to phase-in rate increase if class average total rate increases by more than 15% Phase-in plans are to be opt-in for customer, provide utility with full recovery of carrying costs with return on deferred balance Securitization of deferred balance and carrying charges authorized Utility may propose an early phase-in plan Energy efficiency goal of usage reduction of 2% by 2013 Peak demand reduction goal of 3% by 2012 Utilities may file for cost recovery Procurement Smart Meters Rate Phase-in Program Demand Side Response & Energy Efficiency (DSR/EE) Full deployment of smart meters within 6-10 years Full recovery for net costs of smart meter deployment through base rates or on full and current basis through automatic recovery mechanism Must submit a time-of-use rate plan with voluntary customer participation by the end of rate cap period |
 18 2.63 2.63 0.48 0.48 2.41 6.00 10.54 PECO Average Electric Rates (1) System Average Rates based upon Restructuring Settlement Rate Caps on Energy and Capacity increased from original settlement by 1.6% to reflect the roll-in of increased Gross Receipts Tax and $0.02/kWh for Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustment. System Average Rates also adjusted for sales mix based on current sales forecast. Assumes continuation of current Transmission and Distribution Rates. (2) Energy/Capacity Price is an average of the results for residential (10.51¢/kWh) and small commercial customers (10.58¢/kWh) from the second round of PPL Auction held 10/07. Assumes continuation of current Transmission and Distribution Rates. 2011 2008 – 2010 Energy / Capacity Competitive Transition Charge (CTC) Transmission Distribution 11.52¢ (1) Unit Rates (¢/kWh) Electric Restructuring Settlement +18% 13.65¢ (2) Post Transition Post Transition Projected Rate Increase Based on PPL Auction Results (Illustrative) CTC terminates at year-end 2010 Energy / Capacity price expected to increase; price will reflect associated full requirements costs Using latest PPL auction for 2010 as a proxy (10.5¢/kWh) results in a system average rate increase of ~18% PECO’s 2011 full requirements price expected to differ from PPL due, in part, to the timing of the procurement and locational differences Rates will vary by customer class and will depend on legislation and approved procurement model |
 19 PECO Average Annual Rate Base 2.6 2.8 2.9 3.0 3.1 3.3 2.7 2.0 1.3 1.1 1.1 1.1 1.1 1.2 1.2 0.6 0.6 0.6 0.6 0.5 0.5 0.5 2007E 2008E 2009E 2010E 2011E 2012E Gas CTC Electric Transmission Electric Distribution 6.9 6.4 5.9 5.2 4.9 5.1 ($ in Billions) |
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 21 Exelon Generation Operating Earnings Exelon Generation is poised for significant earnings growth driven by improving market fundamentals, the end of the Pennsylvania transition period, and carbon legislation 2007E (1) 2012 2008E (1) (1) 2007 and 2008 estimated contribution to Exelon operating earnings; see Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. $2,320M - $2,385M 2009 – 2012 Earnings Drivers End of PECO PPA (2011+) Carbon (2012+) Market conditions - Heat rate - Capacity prices - New build costs Nuclear uprates Higher O&M costs Higher nuclear fuel costs Higher interest and depreciation expense 2008 Earnings Drivers Market conditions - Capacity prices - Marginal losses More nuclear outages Higher nuclear fuel costs Higher O&M costs State Line buyout Higher interest and depreciation expense $2,060M - $2,260M |
 22 Long-Run Marginal Cost of Electricity IGCC – No CO2 Recapture Pulverized Coal CCGT Nuclear Excluding energy efficiency, nuclear is the least expensive generation option in a carbon-constrained environment CCGT = Combined Cycle Gas Turbine; IGCC = Integrated Gasification Combined Cycle 0 20 40 60 80 100 120 140 0 5 10 15 20 25 30 35 40 45 50 CO2 Price ($/Metric Ton) |
 23 Hedging Targets Flexibility in our targeted financial hedge ranges allows us to be opportunistic while mitigating downside risk (1) 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: gross margin at the 5th percentile / expected gross margin. Power Team employs commodity hedging strategies to optimize Exelon Generation’s earnings: • Maintain length for opportunistic sales • Use cross commodity option strategies to enhance hedge activities • Time hedging around view of market fundamentals • Supplement portfolio with load following products • Use physical and financial fuel products to manage variability in fossil generation output Target Ranges 50% - 70% 70% - 90% 90% - 98% Above the range* Current Position Upper end of range Midpoint of range Prompt Year (2008) Second Year (2009) Third Year (2010) Financial Hedging Range (1) * Due to ComEd financial swap |
 24 125 127 129 131 133 135 137 139 141 143 145 2004 2005 2006 2007 2008 2009 2010 2011 2012 7 8 9 10 11 12 13 Based on the refueling cycle, we will conduct 12 refueling outages in 2008, versus 9 in 2007, and 10 to 11 in a typical year Note: Net nuclear generation data based on ownership interest; includes Salem. • 18 or 24 months • Duration: ~24 days Nuclear Refueling Cycle • 2008 is an exception: – Salem steam generator replacement – 3 more outages than 2007 • ~2,600 GWh less than 2007 • $100-$110M negative after-tax impact 2008 Refueling Outage Impact Refueling Outage Duration Nuclear Output 0 5 10 15 20 25 30 35 40 45 2000 2001 2002 2003 2004 2005 2006 2007 Exelon (excludes Salem) Industry Actual Target Estimate 2007 Industry data is spring only Impact of Refueling Outages |
 25 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 2007 2008 2009 2010 2011 2012 Effectively Managing Nuclear Fuel Costs Enrichment 38% Fabrication 17% Nuclear Waste Fund 23% Tax/Interest 2% Conversion 3% Uranium 17% Components of Fuel Expense in 2007 0 200 400 600 800 1,000 1,200 1,400 2007 2008 2009 2010 2011 2012 Nuclear Fuel Expense (Amortization + Spent Fuel) Nuclear Fuel Capex Projected Total Nuclear Fuel Spend Projected Exelon Average Uranium Cost vs. Market Projected Exelon Uranium Demand 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2007 2008 2009 2010 2011 2012 Exelon Average Reload Price Projected Market Price (Term) Note: Excludes costs reimbursed under the settlement agreement with the DOE. Market source: UxC composite forecasts. 2007 – 2011: 100% hedged in volume 2012: ~40% hedged in volume All charts exclude Salem, except Projected Total Nuclear Fuel Spend. |
    26 Market Price Sensitivities ~$80M +/- 500 Btu/KWh ATC Heat Rate ~$10M +/- $1/mmBtu Gas Price (Pre-Tax Impact) 2008 EBITDA Sensitivities ($80M) ($40M) ($20M) ($5M) - Expense (Pre-Tax Impact) ($335M) ($160M) ($100M) ($60M) - Capital Expenditures 2012 2011 2010 2009 2008 - $50/lb $40M $15M $10M $5M - Expense (Pre-Tax Impact) $280M $85M $30M $20M - Capital Expenditures 2012 2011 2010 2009 2008 + $50/lb Uranium Sensitivity (1) (1) Excludes Salem. |
 27 Total Portfolio Characteristics The value of our portfolio resides in our nuclear fleet The value of our portfolio resides in our nuclear fleet 40,900 41,100 23,300 23,100 5,100 126,500 120,000 0 50,000 100,000 150,000 200,000 250,000 2007 2008 Actual Hedges & Open Position ComEd Swap IL Auction PECO Load 189,300 190,700 Expected Total Supply (GWh) Expected Total Supply (GWh) Expected Total Sales (GWh) 140,600 138,100 31,600 33,800 18,500 17,400 0 50,000 100,000 150,000 200,000 250,000 2007 2008 Forward / Spot Purchases Fossil & Hydro Nuclear 189,300 190,700 |
 28 Financial Swap Agreement • Market-based contract for ATC baseload energy only – Does not include capacity, ancillary services or congestion • Preserves competitive markets • Fits with Exelon Generation’s hedging policy and strategy • Small portion of Exelon Generation’s supply 3,000 $53.48 January 1, 2013 - May 31, 2013 3,000 $52.37 January 1, 2012 - December 31, 2012 3,000 $51.26 January 1, 2011 - December 31, 2011 3,000 $50.15 June 1, 2010 - December 31, 2010 2,000 $50.15 January 1, 2010 - May 31, 2010 2,000 $49.04 June 1, 2009 - December 31, 2009 1,000 $49.04 January 1, 2009 - May 31, 2009 1,000 $47.93 June 1, 2008 - December 31, 2008 Notional Quantity (MW) Fixed Price ($/MWH) Portion of Term |
 29 Reliability Pricing Model Auction 40.80 197.67 111.92 148.80 102.04 191.32 191.32 Rest of Market Eastern MAAC MAAC + APS 2007/2008 2008/2009 2009/2010 0 1,500 MW N/A N/A N/A N/A MAAC + APS (7) 9,750 - 9,950 MW (3) 9,500 MW 9,550 - 9,850 MW (3) 9,500 MW 9,500 - 9,800 MW (3) 9,500 MW Eastern MAAC 4,750 - 4,950 MW (6) 12,700 MW 6,600 - 6,800 MW 14,500 MW (5) 6,600 - 6,800 MW 16,000 MW (4) Rest of Market Obligation Capacity (2) Obligation Capacity (2) Obligation Capacity (2) 2009 / 2010 2008 / 2009 2007 / 2008 Exelon Generation Participation within PJM Reliability Pricing Model (1) PJM RPM Auction Results ($/MW-day) (6) In 09/10, obligation is reduced due to roll-off of part of ComEd auction load obligation in May 2009. (3) EMAAC obligation consists of load from PECO and BGS commitments. (7) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System. (5) 08/09 Capacity supply decreased due to roll-off of several purchase power agreements (PPAs). (4) Removing State Line from the supply in October 2007 reduces this by 515 MW. (2) All capacity values are in installed capacity terms (summer ratings). (1) All values are approximate and not inclusive of wholesale transactions. |
 30 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 5 10 15 20 25 30 35 40 45 0 5 10 15 20 25 30 Carbon Value Climate change legislation is expected to drive substantial gross margin expansion at Exelon Generation Midwest • ~90,000 GWhs in Midwest nuclear portfolio • ~55% of time coal on the margin • ~40% of time gas on the margin Mid-Atlantic • ~50,000 GWhs in Mid-Atlantic nuclear portfolio • ~45% of time coal on the margin • ~50% of time gas on the margin Carbon Value Assumes Open Position (1) Lieberman-Warner Possible $20 to $40/tonne EIA Carbon Case (3) 2010: $31/tonne Bingaman-Specter (4) 2012: $12/tonne Carbon Credit ($/Tonne) (1) Carbon sensitivity excludes ComEd SWAP and upside of Kincaid/Elwood due to contract expiration in 2012. Assumes below $45/tonne carbon cost, no carbon reduction technology (e.g., sequestration) is economical. (2) As of 12/11/07. (3) The EIA Carbon Stabilization Case (Case 4) dated March 2006, EIA report number SR/OIAF/2006-1. (4) Low Carbon Economy Act initial “Technology Accelerator Payment” (TAP) price in 2012. Allowance price increases at 5% above the rate of inflation thereafter. Europe Carbon Trading 2012: $36.50/tonne (2) |
 31 Potential Nuclear New Build • Intend to file Construction and Operating License (COL) for plant in Texas by end of 2008 – Preserves option to participate in Energy Policy Act incentives • Long-lead material for dual unit ESBWR has been reserved • Texas is attractive market for new nuclear – Growing demand for baseload power, robust market prices – State and local support for new nuclear – Existing Exelon presence in Texas • Exelon’s phased approach allows for go/no-go decisions at major funding/commitment milestones • Exelon’s conditions for new build remain unchanged: the economics must be right Nuclear new build would capitalize on improving fundamentals, high gas prices, and Exelon’s core strength in nuclear operations |
 32 Exelon Nuclear Fleet Overview 2011 42.6% Exelon, 56.4 % PSEG 2016, 2020 969 (1) W PWR 2 Salem, NJ Life of plant capacity 100% AmerGen 2014; renewal to be filed 2008 837 B&W PWR 1 TMI-1, PA Dry cask 100% AmerGen 2009; renewal filed 2005 625 GE BWR 1 Oyster Creek, NJ Dry cask 50% Exelon, 50% PSEG Renewed: 2033, 2034 1135 (1) GE BWR 2 Peach Bottom, PA Dry cask 75% Exelon, 25% Mid- American Holdings Renewed: 2032 1303 (1) GE BWR 2 Quad Cities, IL Dry cask 100% Renewed: 2029, 2031 871, 871 GE BWR 2 Dresden, IL 2012 100% 2022, 2023 1138, 1150 GE BWR 2 LaSalle, IL Dry cask in process 100% 2024, 2029 1151, 1151 GE BWR 2 Limerick, PA Re-rack completed 2011 2013 Spent Fuel Storage/ Date to lose full core discharge capacity GE W W Vendor BWR PWR PWR Type 1 2 2 Units 100% AmerGen 2026 1048 Clinton, IL 100% 2024, 2026 1183, 1153 Byron, IL 100% 2026, 2027 1194, 1166 Braidwood, IL Ownership License Expiration / Status Net Annual Mean Rating MW Plant, Location Fleet also includes 4 shutdown units: Peach Bottom 1, Dresden 1, Zion 1 & 2. (1) Capacity based on ownership interest. |
 33 Energy Policy Act – Nuclear Incentives • $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 • 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 Production Tax Credit (PTC) • 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 • Timing of application subject to DOE solicitations • Loan guarantee volume dependent upon congressional appropriations action • Cost of credit subsidy is still uncertain Government Loan Guarantee • “Insurance” protecting against regulatory and litigation-related delays in commissioning a completed plant • Eligible costs include principal and interest on debt coverage and the incremental cost of replacement power – First two reactors each receive 100% of covered costs up to $500M – The next four reactors each receive 50% of covered costs incurred after six months of delay, up to $250M Regulatory Delay “Backstop” Energy Policy Act provides financial incentives and reduced risk by way of production tax credits and loan guarantees |
 34 Announced Nuclear Projects 22 projects totaling ~40,000 MWs have been announced Letter of intent Greenfield western Idaho TBD TBD Mid-American Nuclear Announced intent Greenfield San Joaquin Valley CA EPR 1 Fresno Nuclear Energy Announced intent Greenfield Bruneau ID EPR 1 Alternative Energy Hldings Letter of intent Operating Turkey Pt FL TBD TBD FPL Letter of intent Operating Susquehanna PA EPR 1 PPL Letter of intent Operating Fermi MI TBD 1 DTE Energy Letter of intent Greenfield Victoria TX ESBWR 2 Exelon Letter of intent Operating Comanche Peak TX APWR 2 TXU Letter of intent Operating Callaway MO EPR 1 Unistar/Ameren Letter of intent Operating Nine Mile Pt NY EPR 1 Unistar COL submitted Sept 2007 Operating South Texas Project TX ABWR 2 NRG Energy Letter of intent Greenfield Amarillo TX EPR 2 Amarillo Power COL Jan 2008 Operating Harris NC AP1000 2 Progress COL 2008 Operating Vogtle GA AP1000 2 Southern COL May 2008 Operating River Bend LA ESBWR 1 Entergy COL submitted December 2007 Characterized Lee SC AP1000 2 Duke COL July 2008 Greenfield Levy Co. FL AP1000 2 Progress Letter of intent Operating Summer SC AP1000 2 South Carolina E&G ESP approved; COL February 2008 Operating Grand Gulf MS ESBWR 1 Entergy/NuStart COL submitted Oct 2007. Reference plant for AP1000 Characterized Bellefonte AL AP1000 2 TVA/NuStart Reference plant for ESBWR COL application; submitted November 2007; ESP approved Operating North Anna VA ESBWR 1 Dominion Partial COL submitted; remainder expected in 2007 Operating Calvert Cliffs MD EPR 1 Unistar Status Type of site Site Technology Units Applicant |
 35 Advanced Nuclear Designs – U.S. Market •Luminant (formerly TXU) Will apply for design certification in 2008 1700 MW Mitsubishi APWR (Advanced PWR) •NRG Evolutionary improvement from current BWR. Design certification in 1997. In operation in Japan since 1996. 1350 MW GE-Hitachi ABWR (Advanced BWR) •UniStar •PPL •Ameren •Alternate Energy Holdings Design certification submitted to NRC. AREVA in UniStar joint venture with Constellation to deploy EPR in US. Under construction in Finland, France 1600 MW AREVA EPR (Evolutionary PWR) •TVA/NuStart •SCE&G •Progress •Duke •Southern PWR, passive safety features, Design certification received December 2005 1150 MW Westinghouse AP1000 (Advanced Passive 1000) •Dominion •Entergy/NuStart at Grand Gulf •Entergy at River Bend •Exelon Passive safety features, simplified from ABWR design. NRC design certification expected 2010 1500 MW GE-Hitachi ESBWR (Economic Simplified Boiling Water Reactor) Selected in US by: Status Capacity Vendor Reactor Sources: World Nuclear Association; Nuclear Fuel Cycle Monitor, September 17, 2007. |
 36 0 1 2 3 4 5 6 7 8 9 10 Building a new nuclear plant is not a one-step process or decision: It is a sequence of 3 successive decisions Years (estimates) 1 2 3 First Decision: File an application for a COL Second Decision: Procure major long-lead procurement components and commodities Third Decision: Proceed with construction Source: Exelon estimates. Roadmap to Nuclear Commercial Operation |
 37 0 20 40 60 80 100 120 140 160 Uranium Price Volatility Long-term equilibrium price expected to be $40-$60/lb 0 20 40 60 80 100 120 140 160 Seven-Month Uranium Price Trend Long-term Uranium Price Trend Spring 2003 McArthur River flood December 2003 GNSS/Tenex termination; ConverDyn UF6 release and shutdown Early 2004 ERA / Ranger water problems Early 2006 First Cigar Lake flood; Cyclone Monica halts ERA / Ranger operations for approximately two weeks October 2006 Second Cigar Lake flood March 2007 ERA / Ranger flooding (cyclone George) |
 38 Current Market Prices 1. 2004, 2005 and 2006 are actual settled prices. 2. Real Time LMP (Locational Marginal Price). 3. Next day over-the-counter market. 4. Average NYMEX settled prices. 5. 2007 information is a combination of actual prices through 12/14/07 and market prices for the balance of the year. 6. 2008 and 2009 are forward market prices as of 12/14/07. PRICES (as of December 14, 2007) Units 2004 1 2005 1 2006 1 2007 5 2008 6 2009 6 PJM West Hub ATC ($/MWh) 42.35 2 60.92 ² 51.07 2 60.52 59.36 57.91 PJM NiHub ATC ($/MWh) 30.15 2 46.39 ² 41.42 2 46.20 44.92 44.75 NEPOOL MASS Hub ATC ($/MWh) 52.13 2 76.65 ² 59.68 2 68.03 75.08 72.20 ERCOT North On-Peak ($/MWh) 49.53 3 76.90 ³ 60.87 3 59.53 75.85 73.19 Henry Hub Natural Gas ($/MMBTU) 5.85 4 8.85 4 6.74 4 6.97 8.25 7.95 WTI Crude Oil ($/bbl) 41.48 4 56.62 4 66.38 4 69.72 90.50 87.48 PRB 8800 ($/Ton) 5.97 8.06 13.04 9.67 12.03 12.18 NAPP 3.0 ($/Ton) 60.25 52.42 43.87 47.54 57.62 55.08 ATC HEAT RATES (as of December 14, 2007) PJM West Hub / Tetco M3 (MMBTU/MWh) 6.40 6.30 6.98 7.77 7.04 6.31 PJM NiHub / Chicago City Gate (MMBTU/MWh) 5.52 5.52 6.32 6.74 6.02 5.43 ERCOT North / Houston Ship Channel (MMBTU/MWh) 7.53 8.21 8.28 8.97 9.19 9.46 |
 39 8.84 9.04 9.24 9.44 9.64 9.84 10.04 10.24 10.44 10.64 10.84 1-07 2-07 3-07 4-07 5-07 6-07 7-07 8-07 9-07 10-07 11-07 12-07 39 7 7.2 7.4 7.6 7.8 8 8.2 8.4 8.6 8.8 1-07 2-07 3-07 4-07 5-07 6-07 7-07 8-07 9-07 10-07 11-07 12-07 55 60 65 70 75 80 85 90 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 7.4 7.6 7.8 8 8.2 8.4 8.6 8.8 9 9.2 9.4 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 Market Price Snapshot As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West On-Peak Implied Heat Rate Ni-Hub On-Peak Implied Heat Rate 2008 2009 2009 2008 2008 PJM-West 2009 PJM-West 2009 Ni-Hub 2008 Ni-Hub 2008 2009 |
 40 25 27 29 31 33 35 37 39 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 40 42 44 46 48 50 52 54 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 40 42 44 46 48 50 52 54 56 58 60 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 50 52 54 56 58 60 62 64 66 68 70 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 Market Price Snapshot PJM-West ATC Forward Prices 2008 2009 PJM-West Wrap Forward Prices 2008 2009 NIHUB ATC Forward Prices NIHUB Wrap Forward Prices 2009 2008 2009 2008 As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. |
 41 47 49 51 53 55 57 59 61 63 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 7.7 7.8 7.9 8 8.1 8.2 8.3 8.4 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 56 58 60 62 64 66 68 70 72 74 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 7 7.5 8 8.5 9 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 Market Price Snapshot 2008 2009 2009 2008 2008 2009 2008 2009 Houston Ship Channel Natural Gas Forward Prices ERCOT North ATC Forward Prices ERCOT North ATC v. Houston Ship Channel Implied Heat Rate ERCOT North Wrap Forward Prices As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. |
 42 42 65 67 69 71 73 75 77 79 81 83 85 1/07 2/07 3/07 4/07 5/07 6/07 7/07 8/07 9/07 10/07 11/07 12/07 Market Price Snapshot ERCOT North On-Peak Forward Prices 2008 2009 As of December 14, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. |
 43 Exelon – Climate Change |
 44 Advancing Exelon’s Low-Carbon Strategy • Lobbying in favor of climate change legislation that is national, mandatory and economy-wide • Taking voluntary action to reduce our greenhouse gas (GHG) emissions 8% from 2001 levels by 2008 • Continuing to invest in our low-carbon generation portfolio • Developing a comprehensive low-carbon energy strategy – Expanding our low-carbon resources – Providing customers with green products and services – Being a model of green operations |
 45 Recognized Environmental Leadership • Named to the 2006/2007 and 2007/2008 Dow Jones Sustainability North America Index • Named to Climate Disclosure Leadership Index of the Carbon Disclosure Project in 2005, 2006 and 2007 • Signatory to the Global Roundtable on Climate Change and the Ceres/Investor Network on Climate Risk statements • Member of the United States Climate Action Partnership (USCAP) • Corporate headquarters awarded Leadership in Energy and Environmental Design (LEED ® ) Platinum Commercial Interiors certification by the U.S. Green Building Council |
 46 Exelon’s Climate Actions • Achieved SF6 leak rate of under 10% for 2006 • Provides customer-based energy-efficiency programs (compact fluorescent light bulbs, demand response programs) – ramping up to one of the country’s leading programs in four years • ComEd is the largest private user of biodiesel in Illinois thereby helping to create a healthy biodiesel market • First utility in PA to file to meet Tier 1 requirements under Alternative Energy Portfolio Standards (AEPS) • Achieved SF6 leak rate of under 10% for 2006 • Supporting implementation of smart meters system-wide and time-of-use programs • Nation’s largest low-carbon generation fleet • Retired older, inefficient plant • Invested in landfill gas power generation expansion Committed to going beyond world-class nuclear performance and compliance with regulations, Exelon is taking voluntary action to address climate change • Largest marketer of wind power east of the Mississippi River • Signed 20-year deal to purchase output from largest solar photovoltaic installation in PJM region |
 47 Exelon and Federal Climate Change Legislation • Actively involved in the climate debate in Washington, D.C. • Lobbying in favor of enacting legislation that is national, mandatory and economy-wide • Favors a cap-and-trade system over a carbon tax • Believes that any allocation scheme should include allowances for distribution companies to help offset the cost of carbon for the end- user • To limit near-term economic impacts, supports a cost containment mechanism, such as a safety valve, that supports a market price for carbon that increases over time |
 48 Reduction Goals 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 Historical U.S. emissions (EPA, 1990-2005) Business-as-usual projection (AEO2007) Sanders-Boxer / Waxman Kerry-Snowe McCain-Lieberman Bingaman-Specter assuming "safety valve" not hit Lieberman-Warner draft principles Olver-Gilchrest Comparison of Economy-wide Cap-and-Trade Emissions Targets Includes Legislation Introduced in the 110th Congress as of September 2007 Bingaman-Specter assumes multiple low-carbon policies, including: •Car & light truck fuel economy of 41 mpg by 2027 •Federal RPS of 15% by 2020 •Optimistic assumptions about new technologies coming online Under these policies, the safety valve is not triggered. Without these policies the safety valve is expected to be reached in the early years and the target will be exceeded. The program ends in 2030 unless the President sets additional long-term targets. |
 49 0 500 1000 1500 2000 2500 3000 3500 1990 1995 2000 2005 2010 2015 2020 2025 2030 Advanced Coal Generation Distributed Energy Resources Plug-In Hybrid Electric Vehicles Carbon Capture & Storage Nuclear Generation Renewables Efficiency Technology Source: Electric Power Research Institute To stabilize emissions at 1990 levels, multiple technologies and intensive R&D will be required CO2 Reductions Demand Multiple Generation Technologies EIA Base Case 2007 • The technical potential exists for the U.S. electricity sector to significantly reduce CO2 emissions over the coming decades • No one technology will be a silver bullet – a portfolio of technologies will be needed • Much of the needed technology is not available yet – substantial R&D, demonstration, and deployment are required |
 50 Key Climate Bills • Several bills and white papers and drafts are gaining support in Washington: – Bingaman-Specter (S. 1766, the Low Carbon Economy Act of 2007) • Economy-wide: All major GHG producing sectors – Point of regulation: Oil and natural gas refineries and coal-fired generators • Increasing auction of allowances – Allowance allocations include: 9% to states, 53% to industry declining 2% per year starting in 2017, 5% set aside for agricultural – Safety Valve: Price of allowances capped at $12/tonne of CO2 (“technology accelerator payment”) starting in 2012 and increasing 5% per year above inflation rate – Lieberman-Warner (S. 2191, America’s Climate Security Act of 2007) • Approved by U.S. Senate Environment and Public Works Committee • Slated for action by the full U.S. Senate in the Spring • Needs 60 votes to break expected filibuster and pass • Economy-wide: All major GHG producing sectors – Seeks to reduce GHG to the 2005 level by 2012; phases to 70% below the 2005 level by 2050 – Points of regulation: Electric power sector – large coal generators; Natural gas – natural gas processors and importers; Industrial sector – large facilities emitting more than 10,000 tonnes per year – “Free” allowances include: 10% to states, 19% to generators (phase out in 2031); 10% to industry; 9% to electric distribution companies, to benefit their customers; 2% to gas distribution companies, to benefit their customers – Creates a Carbon Market Efficiency Board (“Carbon Fed”) with limited authority to oversee market – Dingell-Boucher White Paper • Seeks to reduce emissions by 60% to 80% by 2050 • Best achieved by a cap-and-trade system |
 51 GAAP Reconciliation |
 52 Reconciliation of Net Income to EBITDA GAAP net income (loss) +/- Impact of certain non-operating items Adjusted non-GAAP net income (loss) +/- Cumulative effect of changes in accounting principle +/- Discontinued operations +/- Minority interest + Income taxes Adjusted non-GAAP income (loss) from continuing operations before income taxes and minority interest + Interest expense + Interest expense to affiliates - Interest income from affiliates + Depreciation and amortization Adjusted non-GAAP earnings before interest, taxes, depreciation and amortization (adjusted non-GAAP EBITDA) |
 53 GAAP EPS Reconciliation 2000-2002 2000 GAAP Reported EPS $1.44 Change in common shares (0.53) Extraordinary items (0.04) Cumulative effect of accounting change -- Unicom pre-merger results 0.79 Merger-related costs 0.34 Pro forma merger accounting adjustments (0.07) 2000 Adjusted (non-GAAP) Operating EPS $1.93 2001 GAAP Reported EPS $2.21 Cumulative effect of adopting SFAS No. 133 (0.02) Employee severance costs 0.05 Litigation reserves 0.01 Net loss on investments 0.01 CTC prepayment (0.01) Wholesale rate settlement (0.01) Settlement of transition bond swap -- 2001 Adjusted (non-GAAP) Operating EPS $2.24 2002 GAAP Reported EPS $2.22 Cumulative effect of adopting SFAS No. 141 and No. 142 0.35 Gain on sale of investment in AT&T Wireless (0.18) Employee severance costs 0.02 2002 Adjusted (non-GAAP) Operating EPS $2.41 |
 54 2004 GAAP Reported EPS $2.78 Charges associated with debt repurchases 0.12 Investments in synthetic fuel-producing facilities (0.10) Employee severance costs 0.07 Cumulative effect of adopting FIN 46-R (0.05) Settlement associated with the storage of spent nuclear fuel (0.04) Boston Generating 2004 impact (0.03) Charges associated with investment in Sithe Energies, Inc. 0.02 Charges related to the now terminated merger with PSEG 0.01 2004 Adjusted (non-GAAP) Operating EPS $2.78 2003 GAAP Reported EPS $1.38 Boston Generating impairment 0.87 Charges associated with investment in Sithe Energies, Inc. 0.27 Employee severance costs 0.24 Cumulative effect of adopting SFAS No. 143 (0.17) Property tax accrual reductions (0.07) Enterprises’ Services goodwill impairment 0.03 Enterprises’ impairments due to anticipated sale 0.03 March 3 ComEd Settlement Agreement 0.03 2003 Adjusted (non-GAAP) Operating EPS $2.61 GAAP EPS Reconciliation 2003-2005 2005 GAAP Reported EPS $1.36 Investments in synthetic fuel-producing facilities (0.10) Charges related to the now terminated merger with PSEG 0.03 Impairment of ComEd’s goodwill 1.78 2005 financial impact of Generation’s investment in Sithe (0.03) Cumulative effect of adopting FIN 47 2005 Adjusted (non-GAAP) Operating EPS 0.06 $3.10 |
 55 GAAP Earnings Reconciliation Year Ended December 31, 2006 776 - - 776 - Impairment of ComEd’s goodwill (52) - - (52) - Recovery of debt costs at ComEd (89) - - - (89) Nuclear decommissioning obligation reduction (95) - - (95) - Recovery of severance costs at ComEd $(83) - 1 36 24 - $(144) Other $2,175 1 18 58 24 (58) $1,592 Exelon $455 - 4 10 - - $441 PECO $528 - 4 4 - 3 $(112) ComEd ExGen (in millions) 9 Severance charges 8 Charges related to now terminated merger with PSEG $1,275 2006 Adjusted (non-GAAP) Operating Earnings (Loss) 1 Impairment of Generation’s investments in TEG and TEP - Investments in synthetic fuel-producing facilities (61) Mark-to-market adjustments from economic hedging activities $1,407 2006 GAAP Reported Earnings (Loss) Note: Amounts may not add due to rounding. |
 56 GAAP EPS Reconciliation Year Ended December 31, 2006 $3.22 (0.11) 0.67 $0.78 $1.88 2006 Adjusted (non-GAAP) Operating EPS $2.35 (0.21) 0.65 (0.17) $2.08 2006 GAAP Reported EPS - - - - - 0.05 0.04 - Other (1) (0.14) 1.15 (0.08) - 0.01 0.01 - - ComEd (1) - - - (0.13) 0.01 0.01 - (0.09) ExGen (1) - - - - 0.01 0.01 - - PECO (1) Exelon 1.15 Impairment of ComEd’s goodwill (0.08) Recovery of debt costs at ComEd 0.03 Severance charges (0.13) Nuclear decommissioning obligation reduction (0.14) Recovery of severance costs at ComEd 0.09 Charges related to now terminated merger with PSEG 0.04 Investments in synthetic fuel-producing facilities (0.09) Mark-to-market adjustments from economic hedging activities Note: Amounts may not add due to rounding. (1) Amounts shown per Exelon share and represent contributions to Exelon's EPS. |
 57 GAAP EPS Reconciliation Nine Months Ended September 30, 2006 $2.50 Q3 2006 YTD Adjusted (non-GAAP) Operating EPS (0.08) Recovery of debt costs at ComEd 1.15 Impairment of ComEd's goodwill 0.02 Severance charges (0.13) Nuclear decommissioning obligation reduction 0.09 Charges related to now terminated merger with PSEG 0.08 Investments in synthetic fuel-producing facilities (0.11) Mark-to-market adjustments from economic hedging activities $1.48 Q3 2006 YTD GAAP Reported EPS |
 58 GAAP EPS Reconciliation Nine Months Ended September 30, 2007 $3.31 Q3 2007 YTD Adjusted (non-GAAP) Operating EPS (0.01) Sale of Generation's investments in TEG and TEP 0.14 2007 Illinois electric rate settlement (0.01) Settlement of a tax matter at Generation related to Sithe (0.03) Nuclear decommissioning obligation reduction (0.10) Investments in synthetic fuel-producing facilities 0.12 Mark-to-market adjustments from economic hedging activities $3.20 Q3 2007 YTD GAAP Reported EPS |
 59 2007/2008 Earnings Outlook • Exelon’s outlook for 2007/2008 adjusted (non-GAAP) operating earnings excludes the earnings impacts of the following: – mark-to-market adjustments from economic hedging activities – significant impairments of intangible assets, including goodwill – significant changes in decommissioning obligation estimates – investments in synthetic fuel-producing facilities (2007 only) – costs associated with the Illinois electric rate settlement, including ComEd’s previously announced customer rate relief programs – gains or losses on the State Line Energy, L.L.C. and Tenaska Georgia Partners, LP transactions (2007 only) – other unusual items which the Company is unable to forecast – significant future changes to GAAP • Both our operating earnings and GAAP earnings guidance are based on the assumption of normal weather |
 60 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: Chaka Patterson, Vice President 312-394-7234 Chaka.Patterson@ExelonCorp.com Karie Anderson, Director 312-394-4255 Karie.Anderson@ExelonCorp.com Marybeth Flater, Manager 312-394-8354 Marybeth.Flater@ExelonCorp.com Len Epelbaum, Principal Analyst 312-394-7356 Len.Epelbaum@ExelonCorp.com |