 Bank of America Merrill Lynch Power & Gas Leaders Conference September 29, 2010 Chaka Patterson, Vice President and Treasurer 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 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 Second Quarter 2010 Quarterly Report on Form 10-Q 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 12 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. |
 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 Cooling Water Develop 316(b) Regulations Compliance with 316(b) regulations 3 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/). |
 PJM RPM Capacity Auction Note: Data contained on this slide is rounded. (1) Both supply and demand include effects of First Energy’s generation and forecasted load, respectively, joining PJM. Illustrated unit costs are of existing PJM generation using 2011 fuel prices as of 4/30/2010 (2) Weighted average $/MW-Day would apply if all generation cleared in the highlighted zone. PJM RPM Capacity Prices and Auction ($MW-day) ~$400M Increase EPA Regulations will put upward pressure on energy and capacity clearing prices. 2013/14 RPM auction results in $400 million revenue increase to Exelon over prior auction Left axis PJM Supply Curve (1) Sources: CEMS, Energy Velocity, SNL, Exelon Proprietary Information 74.75 134.46 174.29 110.00 143.90 0 500 1,000 1,500 2009/2010 2010/2011 2011/2012 2012/2013 2013/2014 0 100 200 300 4 |
 5 EPA Clean Air Standards Will Not Threaten Electric System Reliability Proactive steps by EPA, the industry and other agencies will allow orderly plant retirements without impacting system reliability M.J. Bradley and Analysis Group report (1) in August 2010 concluded industry is well-positioned to respond to proposed standards • System has >100 GWs of excess capacity • Regulators have tools to address localized reliability concerns, including appropriate price signals from capacity markets • Industry has proven track record of adding generation capacity and transmission solutions New clean air standards will help modernize US power generation infrastructure • Proven technologies for controls are commercially available: >50% of coal units have installed controls demonstrating that compliance costs can be managed • Pollution-intensive plant retirements will create room for cleaner, more efficient generation (1) M.J. Bradley & Associates, LLC and Analysis Group. 2010. Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability. |
 6 John Deere Renewable Wind Acquisition 735 operating MW of clean, renewable energy, along with 230 MW in advanced stages of development in Michigan 75% of the operating portfolio is contracted Purchase price of $860 million plus an option for $40 million upon commencement of construction of the development projects Attractive economics – EPS and cash flow accretive Acquisition positions Exelon as a large wind operator, complementing its world-class nuclear fleet TX, 26% MO, 22% MI, 17% ID, 12% MN, 11% OR, 10% KS, 2% IL, 1% Transaction Summary Operating Assets – Geographical Distribution |
 7 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 # <10% (2) Electric ~8% 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. (2) Excluding Alternative Energy Portfolio Standards and default service surcharge. Assumes results from final procurement in September 2010 are the same as May 2010 procurement. Note: Electric and gas rate case filings available on Pennsylvania Public Utility Commission (PAPUC) website (www.puc.state.pa.us) or www.peco.com/know. |
 8 ComEd Delivery Rate Case Alternative Regulation (Alt Reg) Proposal ComEd submitted an Alt Reg filing on August 31, 2010 proposing to recover the costs of pre- approved projects outside of the traditional rate case process • 9-month statutory process $60 million proposal would create a collaborative framework for increased investments in the future implementation of ICC-approved Smart Grid investments Customer benefits include: • Assured savings to customers – $2 million on capped O&M costs for program costs (excluding CARE) • An incentive/penalty mechanism for performance above or under budget Proposal would allow for accelerated modernization of the distribution system, increased assistance to low-income households and the purchase of electric vehicles $30 $15 Man-hole refurbishment and cable replacement - $10 Expanded funding for low income CARE programs (1) $5 - Electric Vehicle Fleet Purchase Capital O&M $ millions (1) CARE = Customers’ Affordable Reliable Energy. Total CARE amount for two-year proposal is $20 million. |
 9 Exelon Generation Hedging Disclosures (As disclosed on July 22, 2010) |
 10 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 June 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. |
 11 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 |
 12 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 |
 13 2010 2011 2012 Estimated Open Gross Margin ($ millions) (1)(2) $5,700 $5,300 $5,100 Open gross margin assumes all expected generation is sold at the Reference Prices listed below Reference Prices (1) Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (3) $4.77 $33.17 $44.76 $1.28 $5.34 $32.63 $45.54 $(0.02) $5.68 $34.22 $46.86 $0.53 Exelon Generation Open Gross Margin and Reference Prices (1) Based on June 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, $2.50 variable O&M. |
 14 2010 2011 2012 Expected Generation (GWh) (1) 167,500 163,000 162,600 Midwest 100,000 98,700 97,500 Mid-Atlantic 58,900 57,000 57,000 South 8,600 7,300 8,100 Percentage of Expected Generation Hedged (2) 96-99% 86-89% 57-60% Midwest 96-99 86-89 54-57 Mid-Atlantic 96-99 90-93 59-62 South 97-100 66-69 51-54 Effective Realized Energy Price ($/MWh) (3) Midwest $46.00 $43.50 $44.50 Mid-Atlantic $36.50 $57.50 $51.00 ERCOT North ATC Spark Spread $0.00 $(2.00) $(5.50) Generation Profile (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 10 refueling outages in 2010 and 11 refueling outages in 2011 and 2012 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.1%, 93.2% and 92.9% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected generation in 2011 and 2012 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. Current RMR discussions do not impact metrics presented in the hedging disclosure. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
 15 Gross Margin Sensitivities with Existing Hedges ($ 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 $20 $(15) $10 $(5) $5 $ - +/- $25 2011 $100 $(90) $75 $(65) $30 $(25) +/- $45 2012 $260 $(245) $220 $(210) $130 $(125) +/- $45 Exelon Generation Gross Margin Sensitivities (with Existing Hedges) (1) Based on June 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. |
 16 95% case 5% case $6,600 $6,400 $5,100 $7,100 $6,500 $6,600 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 June 30, 2010. |
 17 Midwest Mid-Atlantic ERCOT Step 1 Start with fleetwide open gross margin $5.70 billion Step 2 Determine the mark-to-market value of energy hedges 100,000GWh * 97% * ($46.00/MWh-$33.17/MWh) = $1.24 billion 58,900GWh * 97% * ($36.50/MWh-$44.76/MWh) = $(0.47 billion) 8,600GWh * 98% * ($0.00/MWh-$1.28/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: $5.70 billion MTM value of energy hedges: $1.24 billion + $(0.47 billion) + $(0.01) billion Estimated hedged gross margin: $6.46 billion Illustrative Example of Modeling Exelon Generation 2010 Gross Margin (with Existing Hedges) |
 18 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 $4.64 2012 $5.26 Rolling 12 months, as of September 8 th , 2010. Source: OTC quotes and electronic trading system. Quotes are daily. Forward NYMEX Coal 2011 $66.50 2012 $74.59 2011 Ni-Hub $37.43 2012 Ni-Hub $39.48 2012 PJM-West $49.82 2011 PJM-West $47.47 2011 Ni-Hub $24.48 2012 Ni-Hub $25.97 2012 PJM-West $36.76 2011 PJM-West $35.09 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 50 55 60 65 70 75 80 85 90 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 35 40 45 50 55 60 65 70 75 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 20 25 30 35 40 45 50 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 |
 19 Market Price Snapshot 2012 $9.14 2011 $9.04 2011 $40.93 2012 $46.82 2011 $4.53 2012 $5.13 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 $5.76 2012 $7.34 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder Rolling 12 months, as of September 8 th , 2010. Source: OTC quotes and electronic trading system. Quotes are daily. 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 40 45 50 55 60 65 70 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 9/09 10/09 11/09 12/09 1/10 2/10 3/10 4/10 5/10 6/10 7/10 8/10 9/10 |
  20 Appendix |
 21 John Deere Renewable Acquisition – Strategic Rationale Diversify with additional clean generation • JDR’s proven wind platform provides unique opportunity and entry point into U.S. wind business • Provides diversity in geographic presence and generation type • Supports Exelon 2020 by adding more “clean” generation to our portfolio and positions us for potential federal renewable portfolio standard (RPS) Contracted portfolio with option for future growth • 75% of operating portfolio sold under long-term PPAs • 1,468 additional MW in pipeline, of which 230 MW have executed PPAs • Only plan further development of contracted assets Attractive economics and good fit • Purchase price compares favorably with other wind transactions • Disciplined investment approach aligned with Exelon’s approach • Addition of strong renewable energy development team Acquisition further enhances Exelon’s strong environmental leadership and provides future opportunities for incremental development |
  22 John Deere Renewable Acquisition – Financials Are Attractive EPS breakeven in 2011, accretive beginning in 2012 • Assumes transaction is funded with 100% debt EBITDA run-rate of ~$150M/year including PTCs (1) (including Michigan development projects) Free cash flow accretive by 2013 • Includes estimated capex (before tax incentives) of $450-$500M in 2011-2012 for Michigan development projects Expect transaction to have minimal impact on credit metrics EPS Accretion / Dilution 0.0% 0.6% 1.5% 2011E 2012E 2013E (1) Production Tax Credits |
 23 23 John Deere Renewable Acquisition Asset Profile – Operating The portfolio is largely made up of contracted operating assets Geographic Distribution TX, 26% MO, 22% MI, 17% ID, 12% MN, 11% OR, 10% KS, 2% IL, 1% Note: There is ongoing litigation with Southwest Public Service related to PURPA contracts which could impact the price at which the generation from these units is sold. Cracking issues experienced by Deere on certain Suzlon turbine blades have been addressed to our satisfaction. We have factored both items into our valuation. Project State MW # of Wind Projects Ownership Placed in Service Date PPA End Date Federal Incentive Off-Taker Idaho 88.2 3 100% 2009/2010 2028/2030 ITC Grant Idaho Power Illinois 8.4 1 99% 2008 2018 PTC Wabash Valley Power Kansas 12.5 1 100% 2010 2030 PTC Kansas Power Pool Michigan 121.8 2 100% 2008 2018/2028 PTC Wolverine Power Supply / Consumers Energy Minnesota 77.7 9 94%-100% 2003/2008 2018/2028 PTC Various Missouri 162.5 4 99%-100% 2008 2027 PTC Associated Electric / MO Joint Municipal Oregon 74.5 4 99%-100% 2009 2029 ITC Grant PacifiCorp Texas 189.8 12 100% 2006/2009 N/A PTC Southwest Public Service Total 735.4 36 |
 24 24 John Deere Renewable Acquisition Asset Profile – Development Pipeline PPAs already executed for these projects Development pipeline includes wind projects ranging from 20 MW to 300 MW Development of projects to be considered on a case-by-case basis State Project Name MW MI Michigan Wind II 90 MI Harvest II 59 MI Blissfield (MW IV) 81 Total 230 Projects to be developed by Exelon Optional projects for development Ohio 198 Michigan 40 Idaho 20 Texas 760 Maine 50 Colorado 40 Oregon 30 California 100 Total 1,238 Total 1,468 |
 111.91 148.80 102.04 191.32 174.29 110.00 16.46 133.37 139.73 27.73 226.15 245.00 2008/2009 2009/2010 2010/2011 2011/2012 2012/2013 2013/2014 RTO MAAC + APS MAAC Eastern MAAC Only shown if cleared at separate price and generation is located in that zone (1) PJM RPM Auction Results Note: Data contained on this slide is rounded. (1) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System. (2) All generation values are approximate and not inclusive of wholesale transactions. (3) All capacity values are in installed capacity terms (summer ratings) located in the areas. (4) Obligation represents the remainder of the ComEd auction load that ends in May 2010. (5) Obligation consists of load obligations from PECO. PECO PPA expires December 2010. (6) Elwood contract expires on 12/31/12 and Kincaid contract expires on 2/28/13. (7) Reflects decision in December 2010 to permanently retire Cromby Station and Eddystone Units 1&2 as of 5/31/11. None of these 933 MW cleared in the 2011/2012 or 2012/2013 auctions. (8) Weighted average $/MW-Day would apply if all generation cleared in the highlighted zones. $134.46 1,500 8,700 (7) 10,300 (6) Capacity (3) 2013/2014 2009/2010 2010/2011 2011/2012 2012/2013 in MW Capacity (3) Obligation Capacity (3) Obligation Capacity (3) Capacity (3) RTO 12,800 3,800 - 4,100 (5) 23,900 9,300 - 9,400 (4) 23,200 12,100 (6) EMAAC 9,500 MAAC + APS 11,100 9,300 – 9,400 (5) MAAC 1,500 Avg ($/MW-Day) (8) $143.90 $174.29 $110.00 $74.75 PJM RPM Auction ($MW-day) 25 Exelon Generation Eligible Capacity within PJM Reliability Pricing Model |
 -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10E 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) 10.2% 2010 annualized growth in gross domestic/metro product (2) 2.9% 4/10 Home price index (3) (1.5)% (1) Source: Illinois Dept. of Employment Security (June 2010) (2) Source: Global Insight (June 2010) (3) Source: S&P Case-Shiller Index (4) Not adjusted for leap year effect 2009 (4) 2Q10 2010E Average Customer Growth (0.4)% 0.2% 0.2% Average Use-Per-Customer (1.0)% 1.4% 0.5% Total Residential (1.4)% 1.6% 0.7% Small C&I (2.2)% (0.1)% (0.6)% Large C&I (6.7)% 4.3% 2.5% All Customer Classes (3.3)% 1.8% 0.8% Weather-Normalized Load Year-over-Year (4) Key Economic Indicators Weather-Normalized Load 26 |
 27 ComEd Delivery Service Rate Case Filing Summary $396 Total ($2,337 million revenue requirement) (6) $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. ICC Docket #: 10-0467, http://www.icc.illinois.gov/docket/casedetails.aspx?no=10-0467. (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. |
 28 3.82 4.73 7.44 7.03 0.73 0.73 0.65 0.60 ComEd Delivery Rate Case Residential Rate Impacts 2010 to 2011 (1) (1) Reflects change in distribution rates only. Assumes Energy, Transmission and all other components remain constant as of June 2010, except as noted above. (2) "All Other" includes impact of riders that are applicable to residential bills. Unit rates: cents / kWh All Other (2) Transmission Energy Distribution Approximately 4% increase July 1, 2010 July 1, 2011 Transmission: Subject to FERC formula rate annual update Comments Energy: Reflects reduced PJM capacity price that PJM has published for the June 2011 – May 2012 planning period. Energy component may vary Distribution: As proposed 12.63 13.09 Note: Amounts may not add due to rounding. Proposed residential rate impact of 7% will be mitigated by impact of lower capacity prices resulting in a net increase of 4% |
 29 ComEd Delivery Service Rate Case Schedule Delivery Service Rate Case Filed – June 30, 2010 Alt Reg Proposal Filed – August 31, 2010 Intervenor and Rebuttal Testimony – 4Q 2010 Hearings – January 2011 Administrative Law Judge Order – March 31, 2011 Final Order Expected – May 2011 New Rates Effective – June 2011 |
 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 Weather-Normalized Load Year-over-Year (3) Key Economic Indicators Weather-Normalized Load 2009 (3) 2Q10 2010E Average Customer Growth (0.2)% 0.2% 0.0% Average Use-Per-Customer (2.1)% (2.5)% 0.3% Total Residential (2.3)% (2.3)% 0.2% Small C&I (2.7)% (5.1)% (1.8)% Large C&I (3.0)% 2.6% 0.9% All Customer Classes (2.6)% (0.7)% 0.1% (1) Source: U.S Dept. of Labor Preliminary data (June 2010) (2) Source: PECO estimate (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 3Q10E 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 30 |
 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. September 2010 results will be public in October. (3) For Large C&I customers who have opted to participate in the 2011 fixed-priced full requirements product. Large Commercial and Industrial Average price of $77.55/MWh 100% of fixed-price full requirements procured in May ’10 (3) Medium Commercial Sept ’09 / May ’10 RFP aggregate result $77.89/MWh Remaining 42% of full requirements procured in Sep ‘10 Residential June ’09 RFP average price of $88.61/MWh Sept ’09 RFP average price of $79.96/MWh May ‘10 RFP average price of $69.38/MWh Remaining 28% of full requirements procured in Sep ‘10 Small Commercial Sept ’09 / May ’10 RFP aggregate result $77.65/MWh Remaining 40% of full requirements procured in Sep ‘10 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 PECO Procurement Plan (1) 2011 Supply Procured (2) Final RFP for 2011 supply was held on September 20, 2010; results will be public on October 14, 2010 |
 32 Exelon Investor Relations Contacts 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: Martha Chavez, Executive Admin Coordinator 312-394-4069 Martha.Chavez@ExelonCorp.com Investor Relations Contacts: Stacie Frank, Vice President 312-394-3094 Stacie.Frank@ExelonCorp.com Melissa Sherrod, Director 312-394-8351 Melissa.Sherrod@ExelonCorp.com Paul Mountain, Manager 312-394-2407 Paul.Mountain@ExelonCorp.com Marybeth Flater, Manager 312-394-8354 Marybeth.Flater@ExelonCorp.com Sandeep Menon, Principal Analyst 312-394-7279 Sandeep.Menon@ExelonCorp.com |