 Earnings Conference Call 3 rd Quarter 2010 October 22, 2010 Exhibit 99.2 |
 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 2009 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 Third Quarter 2010 Quarterly Report on Form 10-Q (to be filed on October 22, 2010) in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I , Financial Information, ITEM 1. Financial Statements: Note 13 and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. This presentation includes references to adjusted (non-GAAP) operating earnings and non-GAAP cash flows that exclude the impact of certain factors. We believe that these adjusted operating earnings and cash flows are representative of the underlying operational results of the Companies. Please refer to the appendix to this presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings. Please refer to the footnotes of the following slides for a reconciliation of non-GAAP cash flows to GAAP cash flows. |
 3 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 YTD 10-year Anniversary 107% 76% 2% EXC UTY S&P 500 (1) Total Shareholder Return is the total return after reinvesting all dividends back into the security at the closing price on the day following the relevant ex-dividend date. Includes stock price appreciation with dividend reinvestment. Excludes taxes and fees. Data as of 10/20/10. (2) Chart represents dividends per share paid by Exelon for 2001 and expected dividend for 2010, which is subject to Board approval. Improvement in ComEd & PECO operating & financial performance Improved reliability records Reasonable regulated returns Hedging strategy creates incremental value Consistently strong earnings and cash flow through various economic and commodity market cycles $0.85 $2.10 2001 2010 Note: Chart above shows capacity factor for ComEd nuclear plants in 1997 and 1998 and Exelon for 1999 and beyond. 2010 capacity factor represents YTD performance. 66% 89% 92.7% - 94.5% 49% Total Shareholder Return (1) since Merger Nuclear Capacity Factor Improvement Dividend Growth (2) Operational & Financial Excellence |
 4 2010 Operating Earnings Guidance 2010 Revised Guidance 2010 Prior Guidance $0.45 - $0.55 $2.80 - $2.95 $3.80 - $4.10 (1) ComEd PECO Exelon Generation ComEd PECO Exelon Generation Holdco Holdco Exelon $0.60 - $0.70 Exelon $3.95 - $4.10 (1) $0.65 - $0.70 $0.50 - $0.55 $2.90 - $3.00 (1) Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. Key Drivers of FY Guidance + Generation margins driven by favorable market conditions and higher nuclear volume + Favorable YTD weather at ComEd and PECO Narrowed 2010 operating earnings guidance to $3.95-$4.10/share (1) |
 5 2017/ 2018 2016/ 2017 2015/ 2016 2014/ 2015 PJM RPM Auctions Delivery Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 EPA Regulations – Market Implications Leading up to 2012 Compliance Air Pollutants Criteria Pollutants Greenhouse Gases Coal Combustion Waste Develop 316(b) Regulations Compliance with 316(b) regulations Develop and Implement New Steam Effluent Guidelines for Wastewater Compliance with Federal Steam Effluent Guidelines Compliance with Federal CCW Regulations Compliance with Federal GHG Reporting Rule PSD/BACT and Title V Applies to GHG Emissions from New and Modified Sources Develop GHG Cap and Trade Legislation or EPA GHG Regulations Under CAA Compliance with GHG Cap and Trade Legislation or EPA GHG Regs Under CAA Compliance with MACT HAP ICR Develop Coal and Oil MACT Develop Clean Air Transport Rule (CATR) Compliance with Transport Rule I Compliance with Transport Rule II Develop Revised NAAQS (Ozone, PM2.5, SO2, NO2) and finalize Transport Rule II Develop Coal Combustion Waste Rule Cooling Water Hazardous Pre-Compliance Period Pre-Compliance Period Pre-Compliance Period Notes: Reliability Pricing Model (RPM) auctions take place annually in May. For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/). |
 6 $1.76 $0.85 $0.88 $0.96 $1.26 $1.60 $1.60 $2.03 $2.10 $2.10 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E Strong, stable dividend remains a key component of shareholder value return Note: CAGR= Compound Annual Growth Rate. Chart represents dividends per share paid by Exelon for 2001-2009 and expected dividend for 2010, which is subject to Board approval. (1) Dividend yield as of October 20, 2010. Competitive Integrated Yield average includes AYE, CEG, EIX, ETR, FE, NEE, PPL, and PEG. Regulated Integrated Yield average includes AEP, AEE, D, DTE, DUK, PCG, PGN, SO, WEC, and XEL. (2) 2001 dividend excludes $0.065 per share pro-rata dividend related to the Unicom-PECO merger. Exelon offers one of the highest yields among its peers Dividend Yield (1) Exelon: 4.7% Competitive Integrateds: 4.2% Regulated Integrateds: 4.6% Historical CAGR (2001-2010) ~10% (2) |
 7 Key Financial Messages Operating results for 3Q10 • Operating earnings of $1.11/share (1) • 95.4% nuclear capacity factor Disciplined hedging program • Adds value to the portfolio while protecting the balance sheet and cash flows Regulatory Update • Settlements reached in PECO electric and gas distribution rate cases, awaiting Pennsylvania Public Utility Commission (PAPUC) approval • ComEd rate case in progress, filed for rehearing of Appellate Court ruling (1) Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. |
 8 Operating EPS (1) Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. $0.76 $0.14 $0.75 $0.19 $0.07 $0.18 2009 2010 $2.50 $0.42 $2.10 $0.51 $0.55 $0.38 2009 2010 HoldCo/Other ExGen PECO ComEd $1.14 $1.27 GAAP EPS Year-to-Date (YTD) (1) $3.10 $3.19 $3.21 $3.08 $1.11 $0.96 Strong performance at the utilities drove quarter over quarter earnings higher; 3Q10 earnings exceeded guidance of $1.00-$1.10/share 3 rd Quarter (3Q) (1) |
 9 Exelon Generation Operating EPS Contribution 2010 2009 Key Drivers – 3Q10 vs. 3Q09 (1) Lower energy prices under the PECO PPA, offset at PECO: $(0.09) Higher nuclear fuel costs: $(0.03) Higher depreciation expense: $(0.02) Favorable RPM capacity pricing: $0.06 Lower income tax expense due to higher allowed manufacturing deduction: $0.05 (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (2) Outage days exclude Salem. 19 36 Refueling 19 21 Non-refueling 3Q10 3Q09 Outage Days (2) 3Q YTD $0.76 $2.50 $0.75 $2.10 Note: PPA = Power Purchase Agreement |
 10 Key Drivers – 3Q10 vs. 3Q09 (1) Weather: $0.06 Reversal of 1Q09 IL tax ruling: $0.05 Uncollectible rider: $0.02 Increased storm costs: $(0.01) ComEd Operating EPS Contribution (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 2010 2009 3Q YTD $0.07 $0.38 3Q10 Actual Normal % Change Heating Degree-Days 70 110 (36.4)% Cooling Degree-Days 854 624 36.9% $0.18 $0.55 |
 11 PECO Operating EPS Contribution Key Drivers – 3Q10 vs. 3Q09 (1) Increased CTC revenue resulting in lower energy prices paid to Generation under the PPA, offset at Generation: $0.09 Weather: $0.05 Higher O&M, primarily bad debt due to increased revenue: $(0.02) CTC amortization $(0.06) 2010 2009 (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 3Q YTD $0.14 $0.42 3Q10 $0.19 $0.51 Actual Normal % Change Heating Degree-Days 0 36 n/a Cooling Degree-Days 1,212 939 29.1% |
 12 -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10E -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% All Customer Classes Large C&I Residential Gross Metro Product ComEd Load Trends Note: C&I = Commercial & Industrial Chicago Unemployment rate (1) 10.0% 2010 annualized growth in gross metro product (2) 2.1% 7/10 Home price index (3) (1.7)% (1) Source: Illinois Dept. of Employment Security (August 2010) (2) Source: Global Insight (September 2010) (3) Source: S&P Case-Shiller Index (4) Not adjusted for leap year effect 2009 (4) 3Q10 2010E Average Customer Growth (0.4)% 0.3% 0.3% Average Use-Per-Customer (1.0)% (2.3)% (0.8)% Total Residential (1.4)% (2.0)% (0.5)% Small C&I (2.2)% 0.8% (0.6)% Large C&I (6.7)% 5.2% 2.5% All Customer Classes (3.3)% 1.1% 0.4% Weather-Normalized Load Year-over-Year Key Economic Indicators Weather-Normalized Load (4) |
 13 PECO Load Trends Philadelphia Unemployment rate (1) 9.2% 2010 annualized growth in gross domestic/metro product (2) 0.8% Note: C&I = Commercial & Industrial Key Economic Indicators Weather-Normalized Load 2009 (3) 3Q10 2010E Average Customer Growth (0.2)% 0.4% 0.2% Average Use-Per-Customer (2.1)% 2.1% 0.9% Total Residential (2.3)% 2.5% 1.1% Small C&I (2.7)% 0.1% (1.6)% Large C&I (3.0)% (1.0)% 0.3% All Customer Classes (2.6)% 0.5% 0.2% (1) Source: U.S Dept. of Labor Preliminary data (August 2010) (2) Source: Moody’s Economy.com August 2010 (3) Not adjusted for leap year effect -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10E -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% All Customer Classes Large C&I Residential Gross Metro Product Weather-Normalized Load Year-over-Year (3) |
 14 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2011 2012 Underlying Options Q3 2010 Ratable Exelon Generation Hedging Program 14 2012 hedging levels currently above ratable • Increased rate of 2012 sales in 2 Quarter of 2010 to capture higher prices in Mid-Atlantic • Participation in long-term procurements Normal practice is to hedge commodity risk on a ratable basis over three years • Maintain flexibility from quarter to quarter • Use of gas and power options to capture potential upside while providing downside price protection Note: % values represent amount above ratable plan 1% 8% Exelon’s ratable hedging program provides flexibility to time sales based on fundamental view of the market (1) Data as of end of 3Q 2010 30.00 35.00 40.00 45.00 50.00 55.00 1/4/10 2/3/10 3/5/10 4/4/10 5/4/10 6/3/10 7/3/10 8/2/10 9/1/10 5.00 5.20 5.40 5.60 5.80 6.00 6.20 6.40 6.60 6.80 7.00 PJMW Hub NiHub Henry Hub Nat Gas 2012 Historic Power & Gas Prices Current Hedge Level vs. Ratable Plan (1) nd |
 15 2010 Projected Sources and Uses of Cash (1) Excludes counterparty collateral activity. (2) Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than capital expenditures and John Deere Acquisition. Cash Flow from Operations for PECO and Exelon includes $550 million for competitive transition charges. (3) Assumes 2010 dividend of $2.10/share. Dividends are subject to declaration by the Board of Directors. (4) Represents new business and smart grid/smart meter investment. (5) Excludes ComEd’s $191 million of tax-exempt bonds that are backed by letters of credit (LOCs). Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms on September 7, 2010. (6) Excludes ComEd’s tax-exempt bonds. PECO’s planned debt retirement of $400 million represents the final retirement of the PECO Energy Transition Trust. ExGen retirements reflect the repurchase of $212M in tax exempt bonds previously backed by letters of credit. ExGen retains the ability to reissue the tax-exempt bonds at a future date or refinance with taxable bonds. (7) “Other” includes PECO Parent Receivable, proceeds from options and expected changes in short-term debt. (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities. ($ millions) Exelon (8) Beginning Cash Balance (1) $1,050 Cash Flow from Operations (1)(2) 1,125 1,100 2,425 4,725 CapEx (excluding Nuclear Fuel, Nuclear Uprates and Solar Project, Utility Growth CapEx) (725) (400) (800) (1,940) Nuclear Fuel n/a n/a (850) (850) Dividend (3) (1,400) Nuclear Uprates and Solar Project n/a n/a (275) (275) Utility Growth CapEx (4) (200) (100) n/a (300) John Deere Renewables Acquisition n/a n/a (860) (860) Net Financing (excluding Dividend): Planned Debt Issuances (5) 500 -- 900 1,400 Planned Debt Retirements (6) (225) (400) (200) (1,225) Other (7) (75) 150 50 (25) Ending Cash Balance (1) $300 |
  16 Exelon Generation Hedging Disclosures (as of September 30, 2010) |
 17 17 Important Information The following slides are intended to provide additional information regarding the hedging program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon Generation’s gross margin (operating revenues less purchased power and fuel expense). The information on the following slides is not intended to represent earnings guidance or a forecast of future events. In fact, many of the factors that ultimately will determine Exelon Generation’s actual gross margin are based upon highly variable market factors outside of our control. The information on the following slides is as of September 30, 2010. We update this information on a quarterly basis. Certain information on the following slides is based upon an internal simulation model that incorporates assumptions regarding future market conditions, including power and commodity prices, heat rates, and demand conditions, in addition to operating performance and dispatch characteristics of our generating fleet. Our simulation model and the assumptions therein are subject to change. For example, actual market conditions and the dispatch profile of our generation fleet in future periods will likely differ – and may differ significantly – from the assumptions underlying the simulation results included in the slides. In addition, the forward-looking information included in the following slides will likely change over time due to continued refinement of our simulation model and changes in our views on future market conditions. |
 18 18 Portfolio Management Objective Align Hedging Activities with Financial Commitments Power Team utilizes several product types and channels to market • Wholesale and retail sales • Block products • Load-following products and load auctions • Put/call options Exelon’s hedging program is designed to protect the long-term value of our generating fleet and maintain an investment-grade balance sheet • Hedge enough commodity risk to meet future cash requirements if prices drop • Consider: financing policy (credit rating objectives, capital structure, liquidity); spending (capital and O&M); shareholder value return policy Consider market, credit, operational risk Approach to managing volatility • Increase hedging as delivery approaches • Have enough supply to meet peak load • Purchase fossil fuels as power is sold • Choose hedging products based on generation portfolio – sell what we own • Heat rate options • Fuel products • Capacity • Renewable credits % Hedged High End of Profit Low End of Profit Open Generation with LT Contracts Portfolio Optimization Portfolio Management Portfolio Management Over Time |
 19 19 Percentage of Expected Generation Hedged • How many equivalent MW have been hedged at forward market prices; all hedge products used are converted to an equivalent average MW volume • Takes ALL hedges into account whether they are power sales or financial products Equivalent MWs Sold Expected Generation = Our normal practice is to hedge commodity risk on a ratable basis over the three years leading to the spot market • Carry operational length into spot market to manage forced outage and load-following risks • By using the appropriate product mix, expected generation hedged approaches the mid-90s percentile as the delivery period approaches • Participation in larger procurement events, such as utility auctions, and some flexibility in the timing of hedging may mean the hedge program is not strictly ratable from quarter to quarter Exelon Generation Hedging Program |
 20 20 2010 2011 2012 Estimated Open Gross Margin ($ millions) (1)(2) $5,650 $4,800 $4,700 Open gross margin assumes all expected generation is sold at the Reference Prices listed below Reference Prices (1) Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (3) $4.42 $32.84 $44.41 $1.77 $4.44 $29.92 $41.07 $(0.37) $5.07 $31.89 $43.10 $0.31 Exelon Generation Open Gross Margin and Reference Prices (1) Based on September 30, 2010 market conditions. (2) Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental revenues. Open gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices. Open gross margin assumes there is no hedging in place other than fixed assumptions for capacity cleared in the RPM auctions and uranium costs for nuclear power plants. Open gross margin contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and payments. The estimation of open gross margin incorporates management discretion and modeling assumptions that are subject to change. (3) ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M. |
 21 21 2010 2011 2012 Expected Generation (GWh) (1) 166,800 163,400 162,700 Midwest 99,500 99,100 96,900 Mid-Atlantic 58,500 56,500 57,100 South 8,800 7,800 8,700 Percentage of Expected Generation Hedged (2) 97-100% 87-90% 62-65% Midwest 97-100 86-89 61-64 Mid-Atlantic 97-100 93-96 66-69 South 97-100 62-65 49-52 Effective Realized Energy Price ($/MWh) (3) Midwest $46.00 $44.00 $43.50 Mid-Atlantic $37.00 $57.50 $50.50 ERCOT North ATC Spark Spread $0.50 $(1.00) $(4.50) Generation Profile (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Expected generation assumes 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.0%, 93.3% and 93.1% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected generation in 2011 and 2012 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. Current RMR discussions do not impact metrics presented in the hedging disclosure. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
 22 22 Gross Margin Sensitivities with Existing Hedges ($ millions) (1) Henry Hub Natural Gas + $1/MMBtu - $1/MMBtu NI-Hub ATC Energy Price +$5/MWH -$5/MWH PJM-W ATC Energy Price +$5/MWH -$5/MWH Nuclear Capacity Factor +1% / -1% 2010 $10 $(5) $5 $ - $- $ - +/- $10 2011 $30 $(15) $60 $(50) $20 $(15) +/- $40 2012 $225 $(175) $205 $(195) $120 $(115) +/- $40 Exelon Generation Gross Margin Sensitivities (with Existing Hedges) (1) Based on September 30, 2010 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due to correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the various assumptions are also considered. |
 23 23 95% case 5% case $6,550 $6,450 $5,100 $7,200 $6,600 $6,400 Exelon Generation Gross Margin Upside / Risk (with Existing Hedges) $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 2010 2011 2012 (1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market. Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes. These ranges of approximate gross margin in 2011 and 2012 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products and options as of September 30, 2010. |
 24 24 Midwest Mid-Atlantic ERCOT Step 1 Start with fleetwide open gross margin $5.65 billion Step 2 Determine the mark-to-market value of energy hedges 99,500GWh * 98% * ($46.00/MWh-$32.84/MWh) = $1.28 billion 58,500GWh * 98% * ($37.00/MWh-$44.41/MWh) = $(0.42 billion) 8,800GWh * 98% * ($0.50/MWh-$1.77/MWh) = $(0.01) billion Step 3 Estimate hedged gross margin by adding open gross margin to mark-to- market value of energy hedges Open gross margin: $5.65 billion MTM value of energy hedges: $1.28billion + $(0.42billion) + $(0.01) billion Estimated hedged gross margin: $6.50 billion Illustrative Example of Modeling Exelon Generation 2010 Gross Margin (with Existing Hedges) |
 25 25 25 20 25 30 35 40 45 50 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 50 55 60 65 70 75 80 85 90 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 35 40 45 50 55 60 65 70 75 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 Market Price Snapshot Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West and Ni-Hub Wrap Forward Prices 2011 $5.64 2012 $5.99 Rolling 12 months, as of October 13 , 2010. Source: OTC quotes and electronic trading system. Quotes are daily. Forward NYMEX Coal 2011 $67.34 2012 $74.56 2011 Ni-Hub $41.12 2012 Ni-Hub $42.79 2012 PJM-West $55.71 2011 PJM-West $54.17 2011 Ni-Hub $24.83 2012 Ni-Hub $26.30 2012 PJM-West $39.78 2011 PJM-West $38.50 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 th |
 26 26 26 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 35 40 45 50 55 60 65 70 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 10/10 Market Price Snapshot 2012 9.06 2011 8.90 2011 $49.19 2012 $43.26 2011 $5.53 2012 $5.87 Houston Ship Channel Natural Gas Forward Prices ERCOT North On-Peak Forward Prices ERCOT North On-Peak v. Houston Ship Channel Implied Heat Rate 2011 $7.29 2012 $8.87 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder Rolling 12 months, as of October 13 , 2010. Source: OTC quotes and electronic trading system. Quotes are daily. th |
  27 Appendix |
 28 ComEd Delivery Service Rate Case Filing Summary $396 $45 Other adjustments (5) $22 Bad debt costs (resets base level of bad debt to 2009 test year) $55 Pension and Post-retirement health care expenses (4) $95 Capital Structure (3) : ROE – 11.50% / Common Equity – 47.33% / ROR – 8.99% $179 (2) Rate Base: $7,717 million (1) Requested Revenue Increase ($ in millions) Primary drivers of rate request are new plant investment, pension/retiree health care and cost of capital (1) Filed June 30, 2010 based on 2009 test year, including pro forma capital additions through June 2011, and certain other 2010 pro forma adjustments. Updating the depreciation and deferred tax reserves to June 2011 would reduce rate base by an estimated $667 million and would reduce the revenue requirement by approximately $85 million. (2) Includes increased depreciation expense. (3) Requested capital structure does not include goodwill; ICC docket 07-0566 allowed 10.3% ROE, 45.04% equity ratio and 8.36% ROR. ROE includes 0.40% adder for energy efficiency incentive. (4) Reflects 2010 expense levels, compared to 2007 expense levels allowed in last rate case. (5) Includes reductions to O&M and taxes other than income, offset by wage increases, normalization of storm costs and the Illinois Electric Distribution Tax, other O&M increases and decreases in load. (6) Net of Other Revenues. Note: ROE = Return on Equity, ROR = Return on Rate Base, ICC = Illinois Commerce Commission. ICC Docket No. 10-0467 Total ($2,337 million revenue requirement) (6) |
 29 ComEd Customer Usage Breakdown Other 2% Residential 31% Small C&I 36% 380 Large C&I 18% Other Large C&I 13% 3% Leisure & Hospitality 9% Trade, Transportation & Utilities 11% Finance, Professional & Business Services 12% Health & Educational Services 13% Government 52% Manufacturing Customer Usage by Revenue Class Top 380 Customer Usage by Segment Limited survey of select Large C&I customers has indicated an increase in production via longer production runs and additional shifts due to improved economic conditions for manufacturing-based customers, especially in the steel and transportation sectors, along with data center expansions. |
 30 PECO – Electric & Gas Distribution Rate Case Settlements Joint settlement filed with the PAPUC on August 31, 2010 for both electric and gas rate cases Settlements are subject to administrative law judges review and PAPUC approval by mid-December 2010 $20 million $225 million Revenue Requirement Increase in settlement (1) R-2010-2161592 R-2010-2161575 Docket # ~7% Electric ~4% 2011 Distribution Price Increase as % of Overall Customer Bill for Residential customers Gas Rate Case Details New rates scheduled to go into effect on January 1, 2011 (1) Settlements are on an overall revenue requirement basis, meaning no details are provided for allowed ROE, rate base or capital structure. Note: Electric and gas rate case filings available on PAPUC website (www.puc.state.pa.us) or www.peco.com/know. |
 31 PECO Procurement (1) See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s procurement plan and RFP results. (2) Wholesale prices. No Small/Medium Commercial products were procured in the June 2009 RFP. (3) For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product. (4) Large Hourly price includes ancillary services and supplier-provided AEPS cost. Large Commercial and Industrial Large Fixed May ’10 RFP - average price of $77.55/MWh (2)(3) Large Hourly Sept ‘10 RFP - average price of $4.83/MWh (4) Medium Commercial Sept ’09 / May ’10 RFP aggregate result $77.89/MWh (2) Sept ‘10 RFP average price of $70.36/MWh (2) Residential June ’09 RFP average price of $88.61/MWh (2) Sept ’09 RFP average price of $79.96/MWh (2) May ‘10 RFP average price of $69.38/MWh (2) Sept ’10 RFP average price of $66.83/MWh (2) Small Commercial Sept ’09 / May ’10 RFP aggregate result $77.65/MWh (2) Sept ‘10 RFP average price of $70.82/MWh (2) 85% full requirements 15% full requirements spot Medium Commercial (peak demand >100 kW but <= 500 kW) Fixed-priced full requirements (3) Hourly full requirements Large Commercial & Industrial (peak demand >500 kW) 90% full requirements 10% full requirements spot 75% full requirements 20% block energy 5% energy only spot Products Small Commercial (peak demand <100 kW) Residential Customer Class 2011 Supply Procured 2011 supply procured, two auctions per year moving forward PECO Procurement Plan (1) |
 32 5.03 6.26 5.84 0.69 0.51 2.57 8.40 PECO Electric Residential Rate Increases 2010 to 2011 January 1, 2011 January 1, 2010 Total = 14.7¢ Unit Rates (¢/kWh) Proposed Total Bill Increase ~5.1 % Total = 15.4¢ AEPS ~0.7% Smart Meter ~0.6% Default Service surcharge mechanism ~(2.9)% Transmission and Distribution ~7% Transmission surcharge mechanism ~1.2% Distribution Rate Case ~5.5% Energy / Capacity Competitive Transition Charge Transmission Distribution 0.47 Energy Efficiency Surcharge Breakdown of 2010 to 2011 ~5.1% Increase (On Total Bill) Notes: • Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%. • Represents average of all residential rates including the effect of discounted rates provided to low income customers. 0.29 |
 33 PA Gross Receipts Tax (5.90%) Distribution Losses (7.35%) Full Requirements Cost PJM Whub ATC Forward Energy Price Estimated Build-Up of PECO Average Residential Full Requirements Price $76.50/MWh $23.75 - $26.25 $41.50 - $42.50 Full Requirements Costs ($/MWh) Average Full Requirements Retail Sales Price (1) Load Shape & Ancillary Services $5.75 - $6.25 Capacity $11.50 - $12.00 Transmission & Congestion $3.50 - $4.50 Renewable Energy Credits $0.25 Migration, Volumetric Risk & Other $2.75 - $3.25 ~$5.00 ~$4.50 (1) As provided by Exelon Generation. (2) On October 14, 2010 the Independent Evaluator (NERA) announced a wholesale winning bid of $66.83/MWh for PECO’s Fall 2010 RFP Residential Price. (1) As provided by Exelon Generation. (2) On October 14, 2010 the Independent Evaluator (NERA) announced a wholesale winning bid of $66.83/MWh for PECO’s Fall 2010 RFP Residential Price. Average Wholesale Energy Price $66.83 (2) |
 34 PECO Customer Usage Breakdown Other 3% Other Large C&I 24% 150 Large C&I 17% Small C&I 22% Residential 34% 7% Other 13% Transportation, Communication & Utilities 18% Health & Educational Services 18% Manufacturing 22% Petroleum 2% Retail Trade 9% Finance, Insurance & Real Estate 12% Pharmaceuticals Customer Usage by Revenue Class Top 150 Customer Usage by Segment PECO’s load is relatively diversified by customer class and industry |
 35 ComEd and PECO Accounts Receivable ComEd A/R (1) 3Q08 3Q09 3Q10 PECO A/R (1) % of AR $789M $714M $769M (1) Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and include, for PECO, pledged and long-term receivables. >60 days 31-60 days 0-30 days Note: Data contained on this slide is rounded. 3Q08 3Q09 3Q10 $789M $889M $710M |
 36 Sufficient Liquidity -- -- -- -- Outstanding Facility Draws (430) (226) (1) (196) Outstanding Letters of Credit $7,365 $4,834 $574 $1,000 Aggregate Bank Commitments (1) 6,935 4,608 573 804 Available Capacity Under Facilities (2) -- -- -- -- Outstanding Commercial Paper $6,935 $4,608 $573 $804 Available Capacity Less Outstanding Commercial Paper Exelon (3) ($ millions) Exelon bank facilities are largely untapped (1) Excludes previous commitment from Lehman Brothers Bank and commitments from Exelon’s Community and Minority Bank Credit Facility. (2) Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements. (3) Includes other corporate entities. Available Capacity Under Bank Facilities as of October 14, 2010 |
 37 Projected 2010 Key Credit Measures 14.2x 9.5x FFO / Interest Generation / Corp: 62% 35% FFO / Debt 54% 69% Rating Agency Debt Ratio BBB A- A- BBB- S&P Credit Ratings (3) BBB+ A BBB+ BBB+ Fitch Credit Ratings (3) A3 A1 Baa1 Baa1 Moody’s Credit Ratings (3) 2.0x 2.4x FFO / Interest ComEd: 7% (4) 8% (4) FFO / Debt 43% 52% Rating Agency Debt Ratio 4.6x 5.1x FFO / Interest PECO: 25% 23% FFO / Debt 47% 50% Rating Agency Debt Ratio 31% 48% Rating Agency Debt Ratio 85% 43% FFO / Debt 21.3x 11.7x FFO / Interest Generation: 48% 32% 6.2x Without PPA & Pension / OPEB (2) 59% Rating Agency Debt Ratio 23% FFO / Debt 5.9x FFO / Interest Exelon Consolidated: With PPA & Pension / OPEB (1) Notes: Exelon 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) FFO/Debt metrics include the following standard adjustments: debt equivalents for PV of Operating Leases, PPAs, unfunded Pension and OPEB obligations (after-tax) and other minor debt equivalents. (2) Excludes items listed in note (1) above. (3) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of October 22, 2010. (4) Reflects impacts of preliminary agreement with IRS to settle involuntary conversion and CTC positions ($420M). Expected to return to target levels in 2011. For additional information see “Other Income Tax Matters” under Footnote 10 of the Q3 2010 Form 10-Q. |
 38 FFO Calculation and Ratios + Other Non-Cash items (1) - AFUDC/Cap. Interest - Decommissioning activity +/- Change in Working Capital FFO Calculation = FFO - PECO Transition Bond Principal Paydown Net Cash Flows provided by Operating Activities Net Interest Expense Adjusted Interest FFO + Adjusted Interest = Adjusted Interest + Interest on Present Value (PV) of Operating Leases + Interest on imputed debt related to PV of Purchased Power Agreements (PPA) + AFUDC & Capitalized interest - PECO Transition Bond Interest Expense FFO Interest Coverage FFO = Adjusted Debt + Off-balance sheet debt equivalents (2) - PECO Transition Bond Principal Balance + STD + LTD Debt: Adjusted Debt (3) FFO Debt Coverage Rating Agency Capitalization Rating Agency Debt Total Adjusted Capitalization Adjusted Book Debt = Total Rating Agency Capitalization + Off-balance sheet debt equivalents (2) Total Adjusted Capitalization = Rating Agency Debt + Off-balance sheet debt equivalents (2) Adjusted Book 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: Debt to Total Cap (1) Reflects depreciation adjustment for PPAs and operating leases and pension/OPEB contribution normalization. (2) Metrics are calculated in presentation unadjusted and adjusted for debt equivalents for PV of Operating Leases, PPAs, unfunded Pension and OPEB obligations (after-tax) and other minor debt equivalents. (3) Uses current year-end adjusted debt balance. |
 39 3Q GAAP EPS Reconciliation (0.02) - - - (0.02) 2007 Illinois electric rate settlement (0.09) (0.04) - - (0.05) Costs associated with early debt retirements 0.05 - - - 0.05 Nuclear decommissioning obligation reduction (0.01) (0.01) - - - NRG acquisition costs 0.13 - - - 0.13 Unrealized gains related to nuclear decommissioning trust funds 0.12 - - - 0.12 Mark-to-market adjustments from economic hedging activities $1.14 $(0.06) $0.14 $0.07 $0.99 3Q09 GAAP Earnings (Loss) Per Share $0.96 $(0.01) $0.14 $0.07 $0.76 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share Exelon Other PECO ComEd ExGen Three Months Ended September 30, 2009 (0.05) - - - (0.05) Emissions impairment (0.02) - - - (0.02) Retirements of fossil generation units / plant retirements 0.00 - - - 0.00 2007 Illinois electric rate settlement $1.27 $(0.01) $0.19 $0.18 $0.91 3Q10 GAAP Earnings (Loss) Per Share $1.11 $(0.01) $0.19 $0.18 $0.75 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share 0.14 - - - 0.14 Mark-to-market adjustments from economic hedging activities 0.09 - - - 0.09 Unrealized gains related to nuclear decommissioning trust funds Exelon Other PECO ComEd ExGen Three Months Ended September 30, 2010 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. |
 40 YTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. (0.10) (0.01) (0.03) (0.16) 0.10 Non-cash remeasurement of income tax uncertainties (0.10) (0.02) (0.02) (0.02) (0.04) Non-cash charge resulting from health care legislation (0.05) - - - (0.05) Emissions impairment 0.25 - - - 0.25 Mark-to-market adjustments from economic hedging activities (0.05) - - - (0.05) Retirement of fossil generating units $3.08 $(0.09) $0.46 $0.37 $2.34 YTD 2010 GAAP Earnings (Loss) Per Share $3.10 $(0.06) $0.51 $0.55 $2.10 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share (0.01) - - - (0.01) 2007 Illinois electric rate settlement 0.04 - - - 0.04 Unrealized gains related to nuclear decommissioning trust funds Exelon Other PECO ComEd ExGen Nine Months Ended September 30, 2010 (0.08) - - - (0.08) 2007 Illinois electric rate settlement (0.09) (0.04) - - (0.05) Costs associated with early debt retirements (0.20) - - - (0.20) Impairment of certain generating assets (0.03) - - (0.02) (0.01) 2009 severance charges 0.05 - - - 0.05 Nuclear decommissioning obligation reduction (0.03) (0.03) - - - NRG acquisition costs 0.18 - - - 0.18 Unrealized gains related to nuclear decommissioning trust funds 0.12 - - - 0.12 Mark-to-market adjustments from economic hedging activities 0.10 (0.02) - 0.06 0.06 Non-cash remeasurement of income tax uncertainties and reassessment of state deferred income taxes $3.21 $(0.19) $0.42 $0.42 $2.57 YTD 2009 GAAP Earnings (Loss) Per Share $3.19 $(0.10) $0.42 $0.38 $2.50 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share Exelon Other PECO ComEd ExGen Nine Months Ended September 30, 2009 |
 41 2010 Earnings Outlook Exelon’s 2010 adjusted (non-GAAP) operating earnings outlook excludes the earnings effects of the following: • Mark-to-market adjustments from economic hedging activities • Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements • Significant impairments of assets, including goodwill • Costs associated with the 2007 Illinois electric rate settlement agreement • Costs associated with ComEd’s 2007 settlement with the City of Chicago • Costs associated with the retirement of fossil generating units • Non-cash charge resulting from passage of Federal health care legislation • Non-cash remeasurement of income tax uncertainties • External costs associated with Exelon’s proposed acquisition of John Deere Renewables • Impairment of certain emission allowances • Other unusual items • Significant future changes to GAAP Operating earnings guidance assumes normal weather for remainder of the year Operating O&M target excludes the following items: • Exelon Generation: Decommissioning accretion expense • ComEd & PECO: Impact of regulatory riders |