 1 Exelon – Value Driven Sanford C. Bernstein 2007 Carbon Symposium New York, New York October 9, 2007 John F. Young Executive Vice President and Chief Financial Officer Exhibit 99.1 |
 2 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’s 2006 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: Note 18; (2) Exelon’s Second Quarter 2007 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, Exelon Generation Company, LLC, Commonwealth Edison Company, and PECO Energy Company (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. This presentation includes references to adjusted (non-GAAP) operating earnings that exclude the impact of certain factors. We believe that these adjusted operating earnings are representative of the underlying operational results of the company. Please refer to the appendix to the presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings. |
 3 ’06 Earnings (1) : $1,275M ’07E Earnings (2) : $2,320 - $2,385M ’06 EPS (1) : $1.88 ’07 EPS Guidance (2) : $3.45 - $3.55 Total Debt (3) : $1.8B Credit Rating (4) : BBB+ The Exelon Companies Nuclear, Fossil, Hydro & Renewable Generation Power Marketing ‘06 Operating Earnings (1) : $2.2B ‘07E Operating Earnings (2) : $2.8 - $2.9B ‘07 EPS Guidance (2) : $4.15 - $4.30 Assets (12/31/06): $44.3B Total Debt (12/31/06): $13.0B Credit Rating (4) : BBB (1) 2006 Adjusted (Non-GAAP) Operating Earnings and Operating EPS. (2) Estimated 2007 Adjusted (Non-GAAP) Operating Earnings and 2007 Operating Earnings Guidance per Exelon share. (3) As of 12/31/06. (4) Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and senior secured debt ratings for ComEd and PECO as of 10/1/07. Pennsylvania Utility Illinois Utility ’06 Earnings (1) : $528M $455M ’07E Earnings (2) : $130 - $165M $435 - $470M ’06 EPS (1) : $0.78 $0.67 ’07 EPS Guidance (2) : $0.20 - $0.25 $0.65 - $0.70 Total Debt (3) : $4.6B $4.2B Credit Ratings (4) : BBB A |
 4 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 |
 5 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) Reduced emissions from fleet – 35% of ComEd’s fleet is hybrid vehicles and uses biodiesel across diesel fleet 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 Preparing to implement smart meters system-wide and time-of-use programs Retired older, inefficient plant Invested in landfill gas power generation expansion Reduced power purchase requirements at some nuclear plants 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 |
 6 Exelon’s Generation Portfolio * Megawatts based on Exelon Generation’s ownership as of 12/31/06. Total Capacity* Owned: 25,543 MW Contracted: 7,691 MW Total: 33,234 MW Fossil & Hydro 20% Nuclear 76% Forward & Spot Purchases 4% 2007 Expected Supply (185 TWh) Exelon is strategically positioned for carbon legislation Exelon is strategically positioned for carbon legislation Generating Plants MW* Nuclear Hydro Coal/Oil/Gas Base-load Intermediate Peaker 16,945 1,606 3,162 3,408 8,113 |
 7 Exelon’s Strategic Direction Protect Today’s Value • Deliver superior operating performance – Keep the lights on – Continue nuclear excellence • Support competitive markets – Maintain/bolster PJM – Step up advocacy – Encourage market-based new entry • Protect the value of our generation – Optimize the generation portfolio – Hedge market risk appropriately • Build healthy, self-sustaining delivery companies – ComEd – drive path to financial health – PECO – maintain performance and prepare for 2011 transition to market Grow Long-Term Value • Take the organization to the next level of performance – Foster positive employee relations – Require accountability for results and values – Acquire, develop and retain key talent – Continuously improve productivity • Align our financial management policies with the changing profile of our company • Rigorously evaluate new growth opportunities – Generation – Transmission – Distribution • Advance an environmental strategy that leverages our carbon position – Provide environmental benefits that also make good business sense – Build a low-carbon resource portfolio + |
 8 Exelon and Federal Climate Change Legislation Climate change is real and results from human-caused greenhouse gas (GHG) emissions 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 “safety valve” for cost of carbon that needs to increase over time |
 9 Allocation Methods Auction Government - Load-Based Allocation Distribution Companies Input-Based Allocation Output-Based Allocation Generators Carbon Emissions MWhs Metric to Allocate? Who gets the carbon allowance? Exelon believes any allocation scheme should include allowances for distribution companies to help offset the cost of carbon for the end-user Exelon believes any allocation scheme should include allowances for distribution companies to help offset the cost of carbon for the end-user |
 10 Key Climate Bills Several bills and drafts are gaining support in Washington: • Bingaman-Specter (Low Carbon Economy Act) Economy-wide: All major GHG producing sectors o Point of regulation: Oil and natural gas refineries and coal-fired generators Increasing auction of allowances o Allowance allocations include: 9% to states, 53% to industry declining 2% per year starting in 2017, 5% set aside for agricultural o Safety Valve: Price of allowances capped at $12/ton of CO2 (“technology accelerator payment”) starting in 2012 and increasing 5% per year above inflation rate • Lieberman-Warner Draft Economy-wide: All major GHG producing sectors o Point of regulation: Oil and natural gas refineries, electric generators, and other large industrial sources Increasing auction of allowances o Allowance allocations include: 4% to states, 20% to power plants (transitions to zero in 2035), 20% to industry, 10% to electricity load-serving entities o Creates Carbon Market Efficiency Board to allow for borrowing of future year allowances with payback • Dingell-Boucher White Paper Reduce emissions by 60% to 80% by 2050 Best achieved by a cap-and-trade system |
 11 Reduction Goals |
 12 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 and demonstration is required |
 13 Future Power Needs Demand Multiple Generation Sources Geothermal Solar Wind Hydro Coal Natural Gas & Oil Future Demand Nuclear |
 14 Cost of Generation Source: Sanford Bernstein research and analysis. CCGT= Combined Cycle Gas Turbine; IGCC= Integrated Gasification Combined Cycle. At CO2 allowance prices of $17/ton or higher – well below those prevailing in the EU today – the all-in cost of electricity, including operating cost and capital recovery, will likely be lower for a nuclear plant than a conventional coal plant, CCGT or IGCC w/ CO2 capture Long-Run Marginal Cost of Electricity ($/MWh) Conventional Coal CCGT IGCC with CO2 Capture Nuclear $40 $50 $60 $70 $80 $90 $100 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 Price of CO 2 Emissions Allowances ($ per ton) Conventional Coal Plant, No CO2 Capture IGCC With CO2 Capture Nuclear CCGT |
 15 - 500 1,000 1,500 2,000 2,500 3,000 0 5 10 15 20 25 30 35 40 45 Carbon Credit ($/Ton) 0 5 10 15 20 25 30 35 40 Carbon Value Climate change legislation is expected to drive substantial gross margin expansion at Exelon Generation (1) As of 10/4/07. (2) The EIA Carbon Stabilization Case (Case 4) dated March 2006, EIA report number SR/OIAF/2006-1. (3) The Energy Information Administration (EIA) valuation of the McCain Lieberman Bill, EIA report number SR/OIAF/2003-02. (4) Low Carbon Economy Act initial “Technology Accelerator Payment” (TAP) price in 2012. Allowance price increases at 5% above the rate of inflation thereafter. Note: Assumes below $45/ton carbon cost, no carbon reduction technology (e.g., sequestration) is economical. EXC Market Sensitivity 2011: $10/ton Europe Carbon Trading 2011: $33.25/ton (1) 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 McCain Lieberman Bill (3) 2010-11: $22/ton Assumes Open Position at Exelon Generation EIA Carbon Case (2) 2010: $31/ton Bingaman Specter (4) : $12/ton |
 16 Exelon Generation Operating Earnings Drivers: Next Five Years 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 Revised 2007 Guidance (2) Note: See “Key Assumptions” slide in Appendix. (1) Differences in sensitivities are largely due to differences in the amount hedged in 2007 vs. 2011. (2) Operating Earnings Guidance revised from previous range of $2,280M - $2,420M. $2,320M - $2,385M $660 N/A + $10/Ton Carbon $340 $25 +/- 500 Btu/KWh ATC Heat rate $50 $10 +/- $10/MW-Day Capacity $390 $25 +/- $1/mmBtu Gas 2011 2007 Market Sensitivities (1) As of 12/31/06 (After-Tax $M) Exelon Generation’s Competitive Position • Large, low-cost, low-emissions, exceptionally well-run nuclear fleet • Complementary and flexible fossil and hydro fleet • Improving power market fundamentals (heat rates and capacity values) • Potential carbon restrictions |
 17 Exelon: Focused on Climate Change Support competitive markets Support nuclear energy Address climate change |
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 19 Appendix – Other Information |
 20 The Exelon Story – Value Driven • Premier U.S. nuclear generator uniquely positioned to capture market opportunities through operational and commercial excellence • Primary source of Exelon’s value going forward • 12% annual operating EPS growth since inception (1) • Continued strong growth trend through 2011 • Strong balance sheet and financial discipline • Realigned value return framework • Experienced management team • Predictable source of earnings through transition period; preparing for 2011 • Completed the transition to a “wires-only” business with a regulatory recovery plan in place (1) Operating EPS growth rate through 2007 calculated using midpoint of 2007 Operating EPS guidance range. |
 21 $3.22 $3.10 $2.78 $2.61 $2.41 $2.24 $1.93 2000 2001 2002 2003 2004 2005 2006 2007E 10/00 4/01 10/01 4/02 10/02 4/03 10/03 4/04 10/04 4/05 10/05 4/06 10/06 4/07 10/07 Strong Financial Performance 10/20/00 – 9/28/07 Assumes dividend reinvestment Source: Bloomberg EXC 215% UTY 90% Total Shareholder Return Adjusted (non-GAAP) Operating EPS Operating EPS Guidance for 2007 revised to $4.15 - $4.30 or upper half of original guidance range (1) Operating EPS growth rate through 2007 calculated using midpoint of 2007 Operating EPS guidance range. $4.15 - $4.30 |
 22 Revised 2007 Operating EPS Guidance (1) $3.22 $0.78 $0.67 $1.88 $0.65 - $0.70 $3.45 - $3.55 $4.15 - $4.30 $0.20 - $0.25 2006 Operating EPS Actual $ / Share HoldCo/Other ExGen PECO ComEd $0.60 - $0.63 Note: See “Key Assumptions” slide in Appendix. (1) Earnings Guidance; Operating EPS Guidance revised from previous range of $4.00 - $4.30 per share. (2) GAAP Guidance revised on 7/25/07 from previous range of $4.10 - $4.40 per share. 2007 and Beyond Exelon Generation ComEd PECO Exelon expects to see robust earnings growth over next five years driven by Exelon Generation and ComEd’s recovery Operating EPS (1) : $4.15 - $4.30 per share GAAP EPS (2) : $3.70 - $4.00 per share Revised 2007 Operating Earnings Guidance ComEd regulatory recovery plan Improving market fundamentals Gas prices Capacity values Heat rates End of IL and PA transition periods Carbon regulation Earnings Drivers |
 23 Disciplined Financial Management We have an increasingly strong balance sheet that will be deployed both to protect and grow shareholder value • In December, the Exelon Board approved a new “Value Return Policy” • The Policy: – Established a base dividend at $1.76/share, growing modestly over time – Returns excess cash and/or balance sheet capacity through share repurchases After funding maintenance capital and committed dividend In absence of higher value-added growth opportunities – Maintains adequate credit metrics on a prospective basis • Consistent with the Policy, the Exelon Board approved a share repurchase program for up to $1.25 billion of Exelon’s outstanding common stock – Expect to complete within the next six months |
 24 $0 $2 $4 $6 $8 $10 $12 $14 20% 25% 30% 35% 2011 Balance Sheet Capacity (Illustrative) Exelon expects to create substantial incremental balance sheet capacity over the next five years, based on planning assumptions Potential Uses of Balance Sheet Capacity Acquisitions or other growth opportunities Future unfunded liabilities Buffer against potentially lower commodity prices Share repurchases or other value return options Note: Data has not been updated since December 12, 2006 Investor Conference. (1) Available Cash = Cash Flow from Operations - CapEx - Dividends +/- Net Financings. Cash Flow from Operations = Net cash flows provided by operating activities less net cash flows used in investing activities other than capital expenditures. Net Financing (excluding Dividends) = Net cash flows used in financing activities excluding dividends paid on common stock. Assumes annualized dividend of $1.76 per share in 2007, growing 5% annually; actual amounts may vary, subject to board approval. (2) Assumes regulatory recovery plan at ComEd. (3) See “FFO Calculation and Ratios” definitions slide. Adjusted FFO / Debt includes: debt equivalents for purchased power agreements, unfunded pension and other postretirement benefits obligations, capital adequacy for energy trading, and related imputed interest. S&P “BBB” Target Range Unadjusted FFO / Debt (2) Adjusted FFO / Debt (2) (3) 2011 FFO / Debt (Forecasted) (3) |
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 26 Premier Nuclear Operator 40 50 60 70 80 90 100 Exelon Industry Average Capacity Factor Note: Exelon data prior to 2000 represents ComEd-only nuclear fleet Average Capacity Factor Note: Exelon data prior to 2000 represents ComEd-only nuclear fleet 65 70 75 80 85 90 95 100 Operator (# of Reactors) Range 5-Year Average Range of Fleet 2-Yr Avg Capacity Factor (2002-2006) EXC 93.2% Sources: Platt’s, Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy) |
 27 Nuclear 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 market price to decrease due to increasing supply; stabilize based on cost of production Exelon Nuclear is managing fuel costs Exelon Uranium Cost vs. Market 0 10 20 30 40 50 60 70 80 90 100 2007 2008 2009 2010 2011 Exelon average re-load price Projected market price Components of Exelon Nuclear's Fuel Cost in 2006 Uranium 21% Conversion 4% Fabrication 16% Tax/Interest 1% Nuclear Waste Fund 18% Enrichment 40% Exelon Projected Uranium Portfolio 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 2005 2006 2007 2008 2009 2010 2011 Contracted Supply 2003 Demand Projection Current Demand Projection |
 28 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 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 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 Need clarification of implementation specifics Availability of funds to nuclear projects at risk given latest program guidelines Government Loan Guarantee “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 $250M after six months of delay Regulatory Delay “Backstop” Energy Policy Act provides financial incentives and reduced risk by way of production tax credits and loan guarantees |
 29 % Hedged Low End of Profit High End of Profit Portfolio Management Flexibility in our targeted financial hedge ranges allows us to be opportunistic while mitigating downside risk 90% - 98% Prompt Year (2008) Target Financial Hedge (1) Range 50% - 70% 70% - 90% Third Year (2010) Second Year (2009) (1) Percent Financially Hedged is our estimate of the gross margin that is not at risk due to a market price drop and assuming normal generation operating conditions. The formula is: Gross margin at the 5th percentile / Expected Gross margin. Power Team employs commodity hedging strategies to optimize Exelon Generation’s earnings: Maintain length for opportunistic sales Use cross commodity option strategies to enhance hedge activities Time hedging around view of market fundamentals Supplement portfolio with load following products Use physical and financial fuel products to manage variability in fossil generation output |
 30 The transition to competitive power procurement allows Exelon Generation to capture the full market value of its generation portfolio and places more emphasis on hedging and risk management 37,500 Fossil & Hydro 139,750 Nuclear 184,550 Total 7,300 Forward & Spot Purchases 2007 Expected Total Supply (GWh) PECO PPA 22% Other Midwest Sales 42% Other Mid- Atlantic Sales 13% IL Auction 15% Other South Sales 8% Portfolio Characteristics 2007 Expected Total Sales (GWh) |
 31 Fundamentals The overbuild is ending in the Eastern Interconnect New build costs are increasing rapidly and are difficult to project with precision due to limited active construction Cost of New Build Generation Construction (1) 2,123 1,581 1,316 615 428 EIA ($/KW) S&P ($/KW) 700 CCGT 4,000 Nuclear 2,795 – 2,925 IGCC 2,438 Pulverized Coal Gas CT Technology (1) Notes: • EIA estimates from Annual Energy Outlook 2007; capital costs converted to 2006 dollars. • S&P costs from Commodity Report, "Which Power Generation Technologies Will Take the Lead in Response to Carbon Controls," May 11, 2007. • Cost estimates from EIA and S&P are generic and do not take into account site-specific issues such as transmission and fuels access. 2007 2008 2009 2010 2011 2012 2013 Source: WoodMackenzie Year New Capacity is Needed VACAR MRO MAAC NY ERCOT SPP ECAR NEPOOL MAIN |
 32 $12.40 $10.30 $15.50 $1.50 $1.00 $102.51/MWh (36-Month Price) 2006 Auction 2007 Auction ~ $35 $67.20 - $67.50 ~ $41 $98.88/MWh (36-Month Price) $57.70 - $58.45 $102.51/MWh (36-Month Price) 2006 Auction 2007 Auction ~ $35 $67.20 - $67.50 ~ $41 $98.88/MWh (36-Month Price) $57.70 - $58.45 Full Requirements Cost New Jersey BGS Auction for PSEG ATC Forward Energy Price (1) Full-Requirements Costs ($/MWh): The higher full-requirements component is due to increases in costs associated with capacity and congestion (1) Range of forward market prices that traded during the 2006 and 2007 auctions. The 2006 auction occurred on Feb. 6-7, 2006, and the 2007 auction occurred on Feb. 5-7, 2007. $140/MW-Day Transmission and Congestion Migration Risk and Volumetric Risk Capacity Renewable Energy Load Shape and Ancillary Services |
 33 PJM RPM 2007/2008 & 2008/2009 RPM will have limited impact on Exelon’s 2007 earnings due to current contracts and forward sales commitments Eastern MACC • 2007/2008 RPM auction: $197.67/MW-day • 2008/2009 RPM auction: $148.80/MW-day Rest of Market • 2007/2008 RPM auction: $40.80/MW-day • 2008/2009 RPM auction: $111.92/MW-day Southwest MAAC • 2007/2008 RPM auction: $188.54/MW-day • 2008/2009 RPM auction: $210.11/MW-day 2007/2008 System Total CTR Value = 4,599 MW 2008/2009 System Total CTR Value = 5,128 MW 2007/2008 System Total CTR Value = 5,134 MW 2008/2009 System Total CTR Value = 4,717 MW 0 MW 0 MW N/A 0 MW Southwest MAAC 480 - 525 MW 480 - 525 MW NJ BGS 9,000 - 9,300 MW 9,000 - 9,300 MW PECO PPA 9,500 MW Eastern MAAC 6,600 - 6,800 MW 6,600 - 6,800 MW IL Auction 16,000 MW (3) Rest of Market 2008/09 2007/08 Obligation Exelon Generation Capacity Obligation (2) ExGen Capacity (1) RPM = Reliability Pricing Model CTR = Capacity Transfer Rights (1) All values are approximate. (2) Not inclusive of all wholesale transactions. (3) 2008/2009 ExGen Rest of Market Capacity decreases to 15,100 MW due to the roll-off of several PPAs. |
 34 Current Market Prices 1. 2004, 2005 and 2006 are actual settled prices. 2. Real Time LMP (Locational Marginal Price). 3. Next day over-the-counter market 4. Average NYMEX settled prices. 5. 2007 information is a combination of actual prices through 9/28/07 and market prices for the balance of the year. 6. 2008 and 2009 are forward market prices as of 9/28/07. PRICES (as of September 28th, 2007) Units 2004 ¹ 2005 ¹ 2006 ¹ 2007 5 2008 6 2009 6 PJM West Hub ATC ($/MWh) 42.35 ² 60.92 ² 51.07 ² 57.21 61.75 64.46 PJM NiHub ATC ($/MWh) 30.15 ² 46.39 ² 41.42 ² 43.71 46.77 48.70 NEPOOL MASS Hub ATC ($/MWh) 52.13 ² 76.65 ² 59.68 ² 64.70 73.81 76.59 ERCOT North On-Peak ($/MWh) 49.53 ³ 76.90 ³ 60.87 ³ 59.52 70.71 75.85 Henry Hub Natural Gas ($/MMBTU) 5.85 4 8.85 4 6.74 4 6.97 7.95 8.27 WTI Crude Oil ($/bbl) 41.48 4 56.62 4 66.38 4 67.90 76.94 73.75 PRB 8800 ($/Ton) 5.97 8.06 13.04 9.66 10.85 11.65 NAPP 3.0 ($/Ton) 60.25 52.42 43.87 46.33 49.50 50.75 ATC HEAT RATES (as of September 28th, 2007) PJM West Hub / Tetco M3 (MMBTU/MWh) 6.40 6.30 6.98 7.36 6.95 6.96 PJM NiHub / Chicago City Gate (MMBTU/MWh) 5.52 5.52 6.32 6.39 5.96 5.91 ERCOT North / Houston Ship Channel (MMBTU/MWh) 7.53 8.21 8.28 7.82 7.95 8.06 |
 35 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 8.0 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 55 60 65 70 75 80 85 90 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 7.4 7.6 7.8 8 8.2 8.4 8.6 8.8 9 9.2 9.4 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 Market Price Snapshot As of September 27, 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 8.84 8.94 9.04 9.14 9.24 9.34 9.44 9.54 9.64 9.74 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 2008 2009 2009 2008 2008 PJM-West 2009 PJM-West 2009 Ni-Hub 2008 Ni-Hub 2008 2009 |
 36 25 27 29 31 33 35 37 39 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 40 42 44 46 48 50 52 54 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 40 42 44 46 48 50 52 54 56 58 60 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 50 52 54 56 58 60 62 64 66 68 70 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 Market Price Snapshot As of September 27, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. 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 |
 37 49 51 53 55 57 59 61 63 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 7.7 7.75 7.8 7.85 7.9 7.95 8 8.05 8.1 8.15 8.2 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 57 59 61 63 65 67 69 71 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 7 7.5 8 8.5 9 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 Market Price Snapshot 2008 2009 2009 2008 2008 2009 As of September 27, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. 2008 2009 Houston Ship Channel Natural Gas Forward Prices ERCOT ATC Forward Prices ERCOT ATC v. Houston Ship Channel Implied Heat Rate ERCOT Wrap Forward Prices |
 38 65 67 69 71 73 75 77 79 81 83 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 Market Price Snapshot ERCOT On-Peak Forward Prices 2008 2009 As of September 27, 2007. Source: OTC quotes and electronic trading system. Quotes are daily. |
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 40 ComEd Operating Earnings: Next Five Years 2011 (1) 2011 Assumptions (1) Rate base: ~$9.6B Equity (2) : ~45% ROE: ~10% Revised 2007 Guidance (3) Note: See “Key Assumptions” slide in Appendix. (1) Provided solely for illustrative purposes, not intended as earnings guidance. The earnings figure represents a possible scenario that is based on the assumptions shown above as well as assumptions about other factors, including, but not limited to, judgments about changes in load growth, spending and ratemaking proceedings, as well as future economic, competitive and financial market conditions, and the absence of adverse regulatory and legislative developments, all of which are subject to uncertainties and have not been subject to the same degree of analysis as we apply to 2007 forecasts. The scenario should not be relied upon as being necessarily indicative of future results. (2) Reflects equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill). Projected book equity ratio in 2007 is 58%. (3) Original Earnings Guidance of $65M - $125M included anticipated IL Settlement cost, which is now excluded from Operating Earnings. After 2007, 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 $130M - $165M ~$430M 2006 Actual $528M 2007 Assumptions Rate Base: ~$8.1B Equity (2) : ~44% ROE: ~3.5 – 4.5% ComEd Highlights Roll-out of customer rate relief programs per the IL Settlement IPA and new procurement process Regulatory recovery plan - Transmission formula rate approved by FERC, effective May 1, 2007 (subject to hearing and potential refund) - Distribution rate case filing planned for late 3Q07; decision expected 11 months after filing |
 41 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 • Eliminates the IL Attorney General’s challenges to the 2006 auction • Financial swap at market prices • No generation tax |
 42 Financial Swap Agreement 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 • 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 – By June 1, 2010, 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 |
 43 FERC Transmission Rate Order FERC approved $116M in ComEd’s formula transmission rate effective as of 5/1/07, subject to refund ($146M originally requested) • Approved 0.50% ROE adder for RTO participation • Approved capital structure of 58% equity / 42% debt • Denied inclusion of CWIP in the formula, which reduces the original revenue requirement by $12M • Denied incentive rate treatment for West Loop and Grenshaw projects, which reduces the original revenue requirement by $16M Issues set for rehearing: • ROE: Base of 11.7% • Other: Post-retirement healthcare costs, pension asset, future plant additions, material and supply, and cash working capital • Settlement proceedings are underway • Appropriate reserves for potential refunds have been established Since last transmission rate update in 2003, ComEd will have invested more than $800 million in transmission-related plant to meet increasing demand and improve reliability (through 2007). The new transmission rate is expected to increase customer bills by ~1% CWIP = Construction work in progress. |
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 45 PECO Operating Earnings: Next Five Years 2011 (1) 2011 Assumptions (1) Rate Base: ~$4.7B Equity: ~50% ROE: ~10% Revised 2007 Guidance (2) $435M - $470M PECO is expected to provide a predictable source of earnings to Exelon through the remainder of the transition period ~$235M Note: See “Key Assumptions” slide in Appendix. (1) Provided solely for illustrative purposes, not intended as earnings guidance. The earnings figure represents a possible scenario that is based on the assumptions shown above as well as assumptions about other factors, including, but not limited to, judgments about changes in load growth, spending and ratemaking proceedings, as well as future economic, competitive and financial market conditions, and the absence of adverse regulatory and legislative developments, all of which are subject to uncertainties and have not been subject to the same degree of analysis as we apply to 2007 forecasts. The scenario should not be relied upon as being necessarily indicative of future results. (2) Operating Earnings Guidance revised from previous range of $400M - $420M. PECO Highlights Legislative activity: HB 1203 and HB 1530 signed by governor on 7/17/07 Other energy issues are expected to be addressed in a special legislative session that began 9/17/07 PAPUC: Issued POLR rules on 5/10/07 - PUC’s Final Default Service rules provide competitive procurement framework with full cost recovery - PUC’s Price Mitigation Order focuses on customer education to prepare customers for potential rate increase AEPS Act – PECO received favorable ALJ recommended decision on 9/13/07 with a PUC decision expected in 4Q07 on its early procurement filing of 3/07 |
 46 Legislative Overview The Pennsylvania General Assembly introduced four bills that would enable elements of Governor Rendell’s Energy Independence Plan One of the four bills, HB 1203, was passed by the General Assembly and was signed into law on July 17, 2007 • HB 1203 amends the Alternative Energy Portfolio Standards (AEPS) Act by increasing solar obligations and modifying standards that utilities must meet in order to obtain “force majeure” waiver from PAPUC A bill not originally part of the Governor’s Energy Initiative, HB 1530, was passed by the General Assembly and signed into law on July 17, 2007 • Supported by Duquesne Energy, US Steel and ATI • Allows all distribution companies to provide long-term, fixed price contracts for customers with peak demands of 15 MW or greater • Allows Duquesne to own generation to serve customers with peak demands of 20 MW or greater (3-year window to enter into a contract or acquire generation) Legislature agreed to hold a Special Session on Energy Policy that began on September 17, 2007 |
 47 Special Session Agenda Senate has agreed to take up the following topics in the Special Session: • Investment in clean and renewable energy and incentives for conservation without new taxes • Legislation to set standards for liquid fuels Additional legislation supporting the Governor’s Energy Independence Strategy is still under consideration in the Legislature; elements of those bills may be considered in the Special Session: • Procurement • Conservation and renewable power • Rate increase phase-in plan • System benefits charge to support $850M bond initiative • Smart meters and time-of-use pilot • Micro-grids • Pennsylvania Energy Development Authority (PEDA) energy procurement authority • Alternative fuels |
 48 Governor’s Energy Independence Strategy – Legislative Package HB 1200 – PEDA Authorization HB 1203 – Renewable Portfolio Standards Amendment HB 1202 – Liquid Fuels Bill • Procurement using the portfolio model with “lowest reasonable rates” and prioritizes demand side management and alternative energy resources • Allows for long-term, cost-based rates for larger energy users • Provides for 3-year phase-in of rate increases for all customers • Establishes system benefits charge of 0.5 mills/KWh • Mandates time-of-use pilot for all customers and full deployment of “smart meter” program in 6 years • Authorizes Pennsylvania Energy Development Authority (PEDA) to spend the $850M of proceeds from securitization of systems benefit charge • Provides PEDA right to “acquire, buy and sell electric power” Accelerates the minimum thresholds for the acquisition of Solar/Photovoltaic as Tier-1 Resource • Force Majeure language modified to consider “good faith effort” by utilities to procure renewable energy • Sets standards for ethanol content in transportation fuels • Sets standards for bio-diesel content of diesel fuel HB 1201 – PAPUC Statute Bill |
 49 Summary of PAPUC Rulemakings It will likely be effective immediately, as it is a policy statement On hold, pending the conclusion of the Special Session on Energy Will address the benefits of DSR/EE and requirements for utilities to implement such programs Demand Side Response Energy Efficiency (DSR/EE) May 17, 2007 Issued May 10, 2007 Discusses consumer education, conservation and energy efficiency, impact on low income customers Mitigation of Rate Increases May 10, 2007 Issued May 10, 2007 Reflects the PAPUC’s current thinking on application of the regulations Default Service Policy Statement September 15, 2007 Issued May 10, 2007 Addresses issues around procurement, rate design, cost recovery, filing requirements Default Service Regulations Effective Date Final Order Description Rulemaking |
 50 Default Service Provider Regulations/Policy Procurement • Competitive process but no statewide auction • Utility run RFPs or auctions are preferred; portfolio approach is allowed • Staggered auctions/RFPs to avoid high market risk • Long term contracts limited to renewable resources • Non-renewable contracts limited to 1-3 years • Encourages spot market purchases for a portion of supply Cost Recovery • Full cost recovery, no prudence review • Reconciliation not required but is mandatory for AEPS Rate Design • Preference for a single price for each rate class �� Eliminates declining block rates and demand charges • Frequent rate changes – quarterly or monthly, to better track the market • Hourly or monthly pricing for large customers Mitigation • Provides for an opt-in phase-in for increases of >25% for customers <25 KW; must be competitively neutral • Transition period of up to 3 years for rate design changes • Statewide education program • Utility specific education plans to be filed by 12/31/2007 • Encourages energy efficiency and demand response |
 51 PECO Post-2010 Strategy • PECO to propose an auction approach to conduct multiple procurements prior to 2011 • May offer 1-year fixed rate for large energy users • Requirement for some spot market purchases • PECO will file its individual Customer Education Plan with PAPUC by 12/31/07 • PECO will participate in PAPUC Working Group to develop effective statewide campaign • PAPUC action on DSR/EE pending • PECO to begin real-time pricing program in 2008 • Plan to expand current offerings and add new programs, based upon PAPUC rules and cost recovery Procurement Rate Stabilization Consumer Education Demand Side Response & Energy Efficiency (DSR/EE) • Procurement plan will include early, staggered procurement • Rate increase phase-in for residential and small commercial customers offered on an opt-in basis if rate increase > 25% • Three-year phase-out to minimize impact of rate design changes |
 52 2011 PECO Average Electric Rates (1) Rates increased from original settlement by 1.6% to reflect the roll-in of increased Gross Receipts Tax and $0.02/kWh for Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustment. 2.59 2.59 2.59 0.46 0.46 0.46 2.70 2.70 2.70 4.92 5.43 5.43 2006 2007 2008 - 2010 Energy / Capacity Competitive Transition Charge Transmission Distribution 10.67¢ 11.18¢ 11.18¢ Unit Rates (¢/kWh) (1) Electric Restructuring Settlement +4.8% CTC terminates at year-end 2010 Energy / Capacity price is expected to increase; price will reflect associated full requirements costs (including capacity, load shaping, ancillary services, line losses, transmission congestion and gross receipts tax) PECO’s 2011 full requirements price is expected to differ from PPL’s first auction price due, in part, to the timing of the procurement and locational differences Rates will vary by customer class and will depend on legislation and approved procurement model Post-Transition Factors |
 53 Appendix – Key Assumptions, Projected 2007 Credit Measures & GAAP Reconciliation |
 54 Key Assumptions 7.60 6.56 8.41 Chicago City Gate Gas Price ($/mmBtu) 9.00 7.31 9.67 Tetco M3 Gas Price ($/mmBtu) 37.0 37.0 37.5 Effective Tax Rate (%) (4) 0.9 0.6 1.3 ComEd 0.6 1.2 0.9 PECO Electric Delivery Growth (%) (3) 53 77 79 ComEd 98 98 95 PECO Electric Volume Retention (%) 16.60 1.75 0.13 PJM West Capacity Price ($/MW-day) 44.30 1.75 0.13 PJM East Capacity Price ($/MW-day) 5.80 6.32 5.52 NI Hub Implied ATC Heat Rate (mmbtu/MWh) 44.00 41.42 46.39 NI Hub ATC Price ($/MWh) 6.60 6.98 6.30 PJM West Hub Implied ATC Heat Rate (mmbtu/MWh) 59.50 51.07 60.92 PJM West Hub ATC Price ($/MWh) 8.00 6.74 8.85 Henry Hub Gas Price ($/mmBtu) 144,000 71,326 72,376 Total Genco Market and Retail Sales (GWhs) (2) 40,500 (5) 119,354 121,961 Total Genco Sales to Energy Delivery (GWhs) 184,500 190,680 194,337 Total Genco Sales Excluding Trading (GWhs) 94.0 93.9 93.5 Nuclear Capacity Factor (%) (1) 2007 Est. 2006 Actual 2005 Actual (1) Excludes Salem. (2) 2007 estimate includes Illinois Auction Sales. (3) Weather-normalized retail load growth. (4) Excludes results related to investments in synthetic fuel-producing facilities. (5) Sales to PECO only. Notes: 2005 and 2006 prices are average for the year. 2007 prices reflect observable prices as of 9/14/06. |
 55 Projected 2007 Key Credit Measures 62% – 52% 52% 53% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 49% 12% – 20% 18% 17% FFO / Debt 2.5x – 3.5x A 4.4x 4.4x FFO / Interest PECO: 52% – 42% 58% 61% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 43% 25% – 40% 12% 10% FFO / Debt 3.5x – 5.5x BBB 3.0x 3.0x FFO / Interest ComEd: 52% – 42% 40% 58% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 38% 25% – 40% 79% 41% FFO / Debt 3.5x – 5.5x BBB+ 12.4x 6.5x FFO / Interest Generation: 63% 28% 5.6x Without PPA & Pension / OPEB 55% – 45% 70% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 54% 20% – 30% 22% FFO / Debt 3.2x – 4.5x BBB 4.6x FFO / Interest Exelon Cons: “BBB” Target Range (3) S&P Credit Ratings (2) With PPA & Pension / OPEB (1) Notes: Projected credit measures reflect impact of Illinois electric rates and policy settlement. Exelon, ComEd and PECO metrics exclude securitization debt. See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to GAAP. (1) Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits (OPEB) obligations, and capital adequacy for energy trading. Debt is imputed for estimated pension and OPEB obligations by operating company. (2) Current senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO as of 10/1/07. (3) Based on S&P Business Profiles: 7 for Exelon, 8 for Generation and ComEd, and 4 for PECO. Exelon’s balance sheet is strong |
 56 FFO Calculation and Ratios (updated) FFO Calculation = FFO - PECO Transition Bond Principal Paydown + Gain on Sale, Extraordinary Items and Other Non-Cash Items (3) + Change in Deferred Taxes + Depreciation, amortization (including nucl fuel amortization), AFUDC/Cap. Interest Add back non-cash items: Net Income = Adjusted Interest + 7% of Present Value (PV) of Operating Leases + Interest on imputed debt related to PV of Purchased Power Agreements (PPA), unfunded Pension and Other Postretirement Benefits (OPEB) obligations, and Capital Adequacy for Energy Trading (2) , as applicable - PECO Transition Bond Interest Expense Net Interest Expense (Before AFUDC & Cap. Interest) Adjusted Interest FFO + Adjusted Interest FFO Interest Coverage + Capital Adequacy for Energy Trading (2) FFO = Adjusted Debt + PV of Operating Leases + 100% of PV of Purchased Power Agreements (2) + Unfunded Pension and OPEB obligations (2) + A/R Financing Add off-balance sheet debt equivalents: - PECO Transition Bond Principal Balance + STD + LTD Debt: Adjusted Debt (1) FFO Debt Coverage = Total Rating Agency Capitalization + Off-balance sheet debt equivalents (2) - Goodwill Total Adjusted Capitalization = Rating Agency Debt + ComEd Transition Bond Principal Balance + Off-balance sheet debt equivalents (2) Adjusted Book Debt Rating Agency Capitalization Rating Agency Debt = Total Adjusted Capitalization + Adjusted Book Debt + Preferred Securities of Subsidiaries + Total Shareholders' Equity Capitalization: = Adjusted Book Debt - Transition Bond Principal Balance + STD + LTD Debt: Total Adjusted Capitalization Adjusted Book Debt Debt to Total Cap Note: Updated to reflect revised S&P guidelines and company forecast. FFO and Debt related to non-recourse debt are excluded from the calculations. (1) Use current year-end adjusted debt balance. (2) Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital Adequacy for Energy Trading. (3) Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions. |
 57 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 |
 58 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 |
 59 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 |
 60 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 |
 61 2007 Earnings Outlook Exelon’s outlook for 2007 adjusted (non-GAAP) operating earnings excludes the earnings impacts of the following: • costs associated with the Illinois electric rate settlement, including ComEd’s previously announced customer Rate Relief and Assistance Initiative • mark-to-market adjustments from economic hedging activities • investments in synthetic fuel-producing facilities • significant impairments of intangible assets, including goodwill • significant changes in decommissioning obligation estimates • other unusual items • any future changes to GAAP GAAP guidance excludes the impact of unusual items which the Company is unable to forecast, including any future changes to GAAP Both our operating earnings and GAAP earnings guidance are based on the assumption of normal weather |
 62 Net income (loss) +/- Cumulative effect of changes in accounting principle +/- Discontinued operations +/- Minority interest + Income taxes Income (loss) from continuing operations before income taxes and minority interest + Interest expense + Interest expense to affiliates - Interest income from affiliates + Depreciation and amortization Earnings before interest, taxes, depreciation and amortization (EBITDA) Reconciliation of Net Income to EBITDA |
 63 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 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 |