![]() Investor Meetings June 2011 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 2010 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 First Quarter 2011 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 it s forward-looking statements to reflect events or circumstances after the date of this presentation. |
![]() PJM RPM Auction Results 3 Base Auction Clearing Prices ($ / MW – Day) LDA RTO MAAC EMAAC SWMAAC PY 12/13 Single Product $16.46 $133.37 $139.73 $133.37 PY 13/14 Single Product $27.73 $226.15 $245 $226.15 PY 14/15 Limited DR $125.47 $125.47 $125.47 $125.47 Extended Summer DR and Annual Resources $125.99 $136.50 $136.50 $136.50 Increased quantities of uncleared generation in RTO reflect changed bidding behavior by some generators to include the cost of environmental compliance Note: RPM = Reliability Pricing Model; PY = Planning year; LDA = Locational Deliverability Area; DR = Demand response |
![]() Wolf Hollow Acquisition 4 Wolf Hollow Overview Diversifies generation portfolio • Expands geographic and fuel characteristics of fleet • Advances Exelon and Constellation merger strategy of matching load with generation in key competitive markets Creates value for shareholders • Purchase price compares favorably to cost of new build • Free cash flow accretive beginning in 2012; earnings and credit neutral • Eliminates current above market purchase power agreement (PPA) with Wolf Hollow • Enhances opportunity to benefit from future market heat rate expansion in ERCOT Transaction expected to close in Q3 2011 Location Granbury, Texas Commercial Operation Date August 2003 Nominal Net Operating Capacity 720MW Equipment Technology 2 Mitsubishi combined-cycle gas turbines Primary Fuel Natural Gas Secondary Fuel None ERCOT = Electric Reliability Council of Texas |
![]() 5 ComEd Load Trends Chicago U.S. Unemployment rate (1) 8.5% 8.8% 2011 annualized growth in gross domestic/metro product (2) 2.5% 3.2% Note: C&I = Commercial & Industrial Weather-Normalized Load Year-over-Year Key Economic Indicators 2010 1Q11 2011E Average Customer Growth 0.2% 0.4% 0.5% Average Use-Per-Customer (1.4)% (2.2)% 0.1% Total Residential (1.2)% (1.8)% 0.5% Small C&I (0.6)% 0.6% (0.3)% Large C&I 2.6% 1.4% (0.1)% All Customer Classes 0.2% (0.1)% 0.0% (1) Source: U.S. Dept. of Labor (March 2011) and Illinois Department of Security (March 2011) (2) Source: Global Insight February 2011 -6.0% -3.0% 0.0% 3.0% 6.0% 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 -6.0% -3.0% 0.0% 3.0% 6.0% All Customer Classes Large C&I Residential Gross Metro Product Weather-Normalized Load |
![]() ComEd 2010 Rate Case Final Order (ICC Docket No. 10-0467) On 5/24/11, the Illinois Commerce Commission (ICC) issued an order in ComEd’s 2010 distribution rate case – new rates scheduled to go into effect in June 2011 Rate Case Details ICC Order (5/24/11) ComEd Reply Brief (2/23/11) Revenue Requirement Increase $143M (1) $343M Rate Base $6,549M $7,349M ROE 10.50% 11.50% (2) Equity Ratio 47.28% 47.28% (1) Reflects ~$(13)M adjustment to ICC Order (2) Included 40 bp adder for energy efficiency, not approved by ICC 6 |
![]() Illinois Power Agency (IPA) RFP Procurement Note: Chart is for illustrative purposes only. REC = Renewable Energy Credit; RFP = request for proposal June 2011 June 2012 June 2013 June 2014 Financial Swap Agreement with ExGen (ATC baseload energy – notional quantity 3,000 MW) 2011 RFP 2012 RFP 2012 RFP 2013 RFP 2013 RFP 2014 RFP Financial Swap 2010 RFP 2011 RFP 2011 RFP 2012 RFP ICC has approved Standard Products and Annual REC Procurement held in May 2011 – Effective ATC of $34.77/MWh for 9 winning Standard Product suppliers for the 2011-12 plan-year – 2.12 million MWh of renewable resources for the 2011-12 plan-year from 12 winning suppliers – Provisions included: • Annual energy procurements over a three-year time frame • Target a 35%/35%/30% laddered procurement approach • No additional Energy Efficiency, Demand Response purchases • No additional long-term contracts for renewables • No 10% overprocurement for summer peak energy June 2015 Delivery Period Peak Off-Peak June 2011 - May 2012 5,118 4,001 June 2012 - May 2013 1,129 358 June 2013 - May 2014 6,494 6,062 Volume procured in the 2011 IPA Procurement Event (GWh) Term Fixed Price ($/MWh) 1/1/11-12/31/11 $51.26 1/1/12-12/31/12 $52.37 1/13/13-5/31/13 $53.48 7 |
![]() 8 PECO Load Trends Philadelphia U.S. Unemployment rate (1) 8.4% 8.8% 2010 annualized growth in gross domestic/metro product (2) 3.0% 3.2% Note: C&I = Commercial & Industrial 2010 1Q11 2011E Average Customer Growth 0.3% 0.4% 0.4% Average Use-Per-Customer 0.3% 0.2% 1.7% Total Residential 0.5% 0.5% 2.1% Small C&I (1.9)% (1.1)% 0.1% Large C&I 0.8% (2.7)% (1.6)% All Customer Classes 0.1% (1.1)% 0.1% (1) Source: U.S. Dept. of Labor data March 2011 - US U.S. Dept. of Labor prelim. data February 2011 - Philadelphia (2) Source: Global Insight February 2011 -6.0% -3.0% 0.0% 3.0% 6.0% 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 -6.0% -3.0% 0.0% 3.0% 6.0% All Customer Classes Large C&I Residential Gross Metro Product Weather-Normalized Load Year-over-Year Key Economic Indicators Weather-Normalized Load |
![]() 9 PECO Procurement Plan Customer Class Products Residential 75% full requirements 20% block energy 5% energy only spot Small Commercial (peak demand <100 kW) 90% full requirements 10% full requirements spot Medium Commercial (peak demand >100 kW but <= 500 kW) 85% full requirements 15% full requirements spot Large Commercial & Industrial (peak demand >500 kW) Fixed-Priced full requirements (2) Hourly full requirements PECO Procurement Plan (1) Residential – weighted average wholesale prices 80 MW of baseload (24x7) block energy product (for Jan-Dec 2012) – $51.52/MWh 70 MW of Jun-Aug 2011 summer on-peak block energy product – $67.24/MWh 40 MW of Dec 2011-Feb 2012 winter on-peak block energy product – $63.05/MWh Large Commercial and Industrial (Hourly) – weighted average wholesale price 36% of hourly full requirements product (for Jun 2011-May 2012) (3) – $4.97/MWh (4) May 2, 2011 RFP - Fifth in a series of nine procurements for the PUC-approved Default Service Plan Spring 2011 RFP was held on May 2, 2011, with results announced on May 18th (1) See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s procurement plan and RFP results. (2) For Large C&I customers who previously opted to participate in the 2011 fixed-priced full requirements product. (3) Large C&I tranches which were not fully subscribed in the fall 2010 procurement. (4) The price for the hourly full requirements product includes only ancillary services/Alternative Energy Portfolio Standard (AEPS) and miscellaneous costs. The price does not include energy and capacity costs. Energy costs will be based on the PECO Zone Day-Ahead locational marginal pricing (LMP) price, and capacity will be based on the PJM RPM price per day. |
![]() 2010 2011 2012 2013 2014 2015 2016 2017 2018 PJM RPM Auction 14/15 15/16 16/17 17/18 Hazardous Air Pollutants Criteria Pollutants Greenhouse Gases Coal Combustion By-Products Cooling Water Effluents 10 EPA Regulations Will Move Forward in 2011 Develop Toxics Rule Develop ICI MACT Pre Compliance Period Compliance With Toxics Rule Pre Compliance Period Compliance With ICI MACT Develop Transport Rule Compliance With Transport Rule Interim CAIR Develop O3 Transport Rule (TR 2) Estimated Compliance Develop Criteria NSPS revision Compliance with Revised Criteria NSPS Develop Revised NAAQS SIP provisions developed in response to revised NAAQS (e.g., Ozone, PM2.5, SO2, NO2, NOx/SOx, CO) Compliance with Federal GHG Reporting Rule PSD/BACT and Title V Apply to GHG Emissions (PSD only for new and modified sources) Develop GHG NSPS Pre Compliance Period Compliance With GHG NSPS Develop Coal Combustion By-Products Rule Pre Compliance Period Compliance With Federal CCB Regulations Develop 316(b) Regulations Pre Compliance Period Phase In Of Compliance Phase In Of Compliance Develop Effluent Regulations Pre Compliance Period Notes: 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/). |
![]() 11 2011 Events of Interest Q1 Q2 Q3 Q4 RPM Auction results (5/13) Illinois Power Agency RFP (5/16) ALJ Proposed Order – DST Rate Case (4/1) Procurement RFP (bids accepted 5/2; results 5/18) DST Rate Case Final Order (5/24) EPA Final Toxics Rule (November) Retirement of Cromby 1 & Eddystone 1 units (5/31) Proposed Toxics Rule (3/16) Procurement RFP (bids due 9/19; results by 10/19) Retirement of Cromby 2 unit (12/31) Proposed 316(b) EPA Regulation (3/28) EPA Final Transport Rule (June) For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/). |
![]() ![]() 12 Exelon Generation Hedging Disclosures (as of March 31, 2011) |
![]() Important Information 13 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 March 31, 2011. 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. |
![]() 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 14 |
![]() 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 15 |
![]() 2011 2012 2013 Estimated Open Gross Margin ($ millions) (1)(2) $5,250 $4,900 $5,500 Open gross margin assumes all expected generation is sold at the Reference Prices listed below Reference Prices (1) Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (3) $4.47 $31.32 $44.23 $4.42 $5.06 $31.32 $46.19 $1.88 $5.41 $32.83 $48.10 $2.06 Exelon Generation Open Gross Margin and Reference Prices 16 (1) Based on March 31, 2011 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, $2.50 variable O&M. |
![]() 2011 2012 2013 Expected Generation (GWh) (1) 165,800 165,400 162,800 Midwest 99,000 97,800 96,100 Mid-Atlantic 56,300 57,200 56,400 South & West 10,500 10,400 10,300 Percentage of Expected Generation Hedged (2) 93-96% 73-76% 38-41% Midwest 93-96 75-78 35-38 Mid-Atlantic 94-97 72-75 42-45 South & West 76-79 59-62 40-43 Effective Realized Energy Price ($/MWh) (3) Midwest $43.00 $41.00 $41.00 Mid-Atlantic $56.50 $50.50 $50.50 South & West $4.50 $0.00 ($3.00) Generation Profile 17 (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.0%, 93.6% and 93.1% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
![]() Gross Margin Sensitivities with Existing Hedges ($ 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% 2011 $5 $(5) $15 $(10) $10 $(10) +/- $30 2012 $145 $(65) $145 $(125) $90 $(90) +/- $45 2013 $425 $(380) $315 $(310) $180 $(175) +/- $45 Exelon Generation Gross Margin Sensitivities (with Existing Hedges) (1) Based on March 31, 2011 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. 18 |
![]() ![]() 95% case 5% case $5,500 $7,100 $6,800 $6,200 Exelon Generation Gross Margin Upside / Risk (with Existing Hedges) $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 2011 2012 2013 $6,900 $4,900 19 (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 2012 and 2013 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 March 31, 2011. |
![]() Midwest Mid-Atlantic South & West Step 1 Start with fleetwide open gross margin $5.25 billion Step 2 99,000GWh * 94% * ($43.00/MWh-$31.32MWh) = $1.09 billion 56,300GWh * 95% * ($56.50/MWh-$44.23MWh) = $0.66 billion 10,500GWh * 77% * ($4.50/MWh-$4.42/MWh) = $0.00 billion Step 3 Open gross margin: MTM value of energy hedges: Estimated hedged gross margin: Illustrative Example of Modeling Exelon Generation 2011 Gross Margin (with Existing Hedges) 20 Determine the mark-to-market value of energy hedges Estimate hedged gross margin by adding open gross margin to mark-to- market value of energy hedges $5.25 billion $1.09billion + $0.66billion + $0.00 billion $7.00 billion |
![]() Market Price Snapshot Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West and Ni-Hub Wrap Forward Prices 2012 $5.21 2013 $5.49 Forward NYMEX Coal 2012 $78.21 2013 $82.04 2012 Ni-Hub $40.60 2013 Ni-Hub $42.66 2013 PJM-West $54.37 2012 PJM-West $52.35 2012 Ni-Hub $25.18 2013 Ni-Hub $27.24 2013 PJM-West $40.97 2012 PJM-West $39.03 21 Rolling 12 months, as of May 6th 2011. Source: OTC quotes and electronic trading system. Quotes are daily. |
![]() Market Price Snapshot 2013 9.36 2012 9.23 2012 $46.94 2013 $50.23 2012 $5.09 2013 $5.37 Houston Ship Channel Natural Gas Forward Prices ERCOT North On-Peak Forward Prices ERCOT North On-Peak v. Houston Ship Channel Implied Heat Rate 2012 $7.72 2013 $9.00 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder Rolling 12 months, as of May 6th 2011. Source: OTC quotes and electronic trading system. Quotes are daily. 22 |