Earnings Conference Call 1 st Quarter 2011 April 27, 2011 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 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 (to be filed on April 27, 2011) 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. 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 2011 Operating Earnings Guidance 2011 Guidance (2) ComEd PECO Exelon Generation Holdco Exelon $3.90 - $4.20 (1) $0.55 - $0.65 $0.50 - $0.60 $2.85 - $3.05 (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. (2) Earnings guidance for OpCos may not add up to consolidated EPS guidance. Strong operating and financial results in first quarter • Higher than expected operating EPS of $1.17 mainly driven by higher Generation gross margin and PA bonus depreciation • Nuclear capacity factor of 94.8% Reaffirming 2011 operating earnings guidance of $3.90 - $4.20/share (1) |
4 Key Messages EPA’s proposed Air Toxics and 316(b) rules largely as expected • Expect final rules to be implemented on time • Impact to the industry is manageable FERC ruling on PJM MOPR defends competitive markets Exelon’s nuclear plants are safe • Continuing to work with NRC and other stakeholders to evaluate lessons learned and respond to Fukushima event Pursuing projects to increase value • Transmission projects near Clinton and Quad Cities will reduce congestion |
5 Key Financial Messages 1Q 2011 operating earnings of $1.17/share (1) • Quarter results $0.17/share better than prior year • Quarter earnings exceeded guidance as a result of: Favorable market conditions in the South region driven by weather Pennsylvania bonus depreciation Lower O&M cost than expected, primarily timing Expect to generate $4.3 billion cash from operations in 2011 Expect 2Q 2011 operating earnings of $0.90 - $1.00/share (1) (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. |
6 Exelon Generation Operating EPS Contribution 2010 2011 (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. Outage Days (2) 1Q10 1Q11 Refueling 101 44 Non-refueling 5 14 1Q $0.66 $0.90 Note: PPA = Power Purchase Agreement Key Drivers – 1Q11 vs. 1Q10 (1) Higher margins due to expiration of the PECO PPA: $0.19 Favorable capacity pricing: $0.06 Nuclear volume: $0.04 Increased depreciation expense: $(0.02) Higher nuclear fuel costs: $(0.01) Higher interest expense: $(0.01) |
Power Fundamentals & Hedging Update |
8 Key Drivers – 1Q11 vs. 1Q10 (1) 2010 uncollectible expense rider: $(0.06) Appellate Court ruling: $(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 2011 1Q $0.19 1Q11 Actual Normal % Change Heating Degree-Days 3,332 3,208 3.9% $0.11 |
9 9 9 ComEd Load Trends |
10 PECO Operating EPS Contribution Key Drivers – 1Q11 vs. 1Q10 (1) Electric and gas distribution rates: $0.05 2010 CTC collections, net of amortization expense: $(0.05) Lower interest expense: $0.01 2010 2011 (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. 1Q $0.17 1Q11 $0.19 Actual Normal % Change Heating Degree-Days 2,506 2,510 (0.2)% Note: CTC = Competitive Transition Charge |
11 PECO Load Trends |
12 2011 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. (3) Assumes 2011 dividend of $2.10/share. Dividends are subject to declaration by the Board of Directors. (4) Includes $450 million in Nuclear Uprates and $225 million for Exelon Wind spend. (5) Represents new business, smart grid/smart meter investment and transmission growth projects. (6) 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 through September 6, 2011. (7) “Other” includes proceeds from options and expected changes in short-term debt. (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities. |
13 Exelon Generation Hedging Disclosures (as of March 31, 2011) * * * * * * * * * * * * * * * * * * * |
14 14 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 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. |
15 15 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 |
16 16 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 |
17 17 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 (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, $2.50 variable O&M. |
18 18 2011 2012 2013 Expected Generation (GWh) (1) 165,800 165,400 162,800 Midwest 99,000 97,800 96,100 Mid-Atlantic 56,300 57,200 56,400 South & West 10,500 10,400 10,300 Percentage of Expected Generation Hedged (2) 93-96% 73-76% 38-41% Midwest 93-96 75-78 35-38 Mid-Atlantic 94-97 72-75 42-45 South & West 76-79 59-62 40-43 Effective Realized Energy Price ($/MWh) (3) Midwest $43.00 $41.00 $41.00 Mid-Atlantic $56.50 $50.50 $50.50 South & West $4.50 $0.00 ($3.00) Generation Profile (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.0%, 93.6% and 93.1% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
19 19 Gross Margin Sensitivities with Existing Hedges ($ 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. |
20 20 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 (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. $6,900 $4,900 |
21 21 Midwest Mid-Atlantic South & West Step 1 Start with fleetwide open gross margin $5.25 billion Step 2 Determine the mark-to-market value of energy hedges 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 Estimate hedged gross margin by adding open gross margin to mark-to- market value of energy hedges Open gross margin: $5.25 billion MTM value of energy hedges: $1.09billion + $0.66billion + $0.00 billion Estimated hedged gross margin: $7.00 billion Illustrative Example of Modeling Exelon Generation 2011 Gross Margin (with Existing Hedges) |
22 22 35 40 45 50 55 60 65 70 75 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 22 22 20 25 30 35 40 45 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 50 55 60 65 70 75 80 85 90 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 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 $5.26 2013 $5.54 Rolling 12 months, as of April 15th 2011. Source: OTC quotes and electronic trading system. Quotes are daily. Forward NYMEX Coal 2012 $77.69 2013 $81.53 2012 Ni-Hub $40.67 2013 Ni-Hub $42.74 2013 PJM-West $54.38 2012 PJM-West $52.35 2012 Ni-Hub $25.20 2013 Ni-Hub $27.30 2013 PJM-West $40.85 2012 PJM-West $38.94 |
23 23 23 23 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 35 40 45 50 55 60 65 70 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 4/10 5/10 6/10 7/10 8/10 9/10 10/10 11/10 12/10 1/11 2/11 3/11 4/11 Market Price Snapshot 2013 9.35 2012 9.21 2012 $47.30 2013 $50.61 2012 $5.14 2013 $5.42 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 $7.70 2013 $9.02 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder Rolling 12 months, as of April 15th 2011. Source: OTC quotes and electronic trading system. Quotes are daily. |
24 Appendix * * * * * * * * * * * * * * * * * * *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** *************************** |
25 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 due 5/2; results by 5/17) DST Rate Case Final Order (by 5/31) 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) For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/). EPA Final Transport Rule (June) |
26 |
27 Exelon View on Proposed CWA Sec. 316(b) Rule |
28 28 EPA Regulations Will Move Forward in 2011 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 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 Develop Effluent Regulations Pre Compliance Period Phase In Of Compliance 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/). |
29 Factors Influencing PJM RPM Capacity Auction (Comparison of PY 14/15 and PY 13/14 Price Drivers) Exelon Price Impact Cost of Environmental Upgrades (1) Higher Net CONE (2) Higher Net ACRs for Coal Units (3) Import Transmission Limits and Objectives (muted impact on portfolio revenues due to regional diversification) NJ CCGT Proposal / PJM Minimum Offer Price Rules Peak Load (4) Demand Response Growth 2014/15 PJM Capacity Auction: Expected Changes Since Planning Year 2013/14 (1) We expect generators to reflect cost of capital expenditures into their cost based offers at the upcoming auction. (2) Cost of new entry (CONE) increased by 7.6% (for RTO) and 5.3% to 6.5% (within Locational Deliverability Areas (LDAs)). (3) Replacing 2007 net revenues with significantly lower 2010 revenues in the Net ACR (avoidable cost rate) calculations for coal generators may increase offer caps for certain coal generators in the next auction. However, some coal units may not be affected due to high net revenues compared to avoidable costs. (4) Peak load reduced by approx. 1% in RTO (excluding the impact from Duke Ohio integration). Note: RPM = Reliability Pricing Model; CCGT = combined cycle gas turbine Expect overall results to be similar to last year’s auction N/A |
30 Exelon’s Nuclear Plants Are Designed to Withstand Extreme Environmental Hazards None of Exelon’s plants are in major earthquake zones Designed to withstand highest level of seismic activity for that location, with additional margin Regular seismic analyses are performed and the NRC reviews new information on earthquake sources and ground motion models to determine if changes are necessary Emergency core cooling systems are protected from water incursion, including water tight doors, elevation of equipment above potential flood levels and/or special engineered flood barriers (on a site-specific basis) Fuel tanks are buried underground or enclosed in buildings Switchgear for emergency operations are elevated above flood levels All but one of Exelon’s plants are in Illinois and Pennsylvania Oyster Creek (in NJ) is more than 5 miles inland, behind barrier islands • Tsunamis are extremely rare in the mid-Atlantic • Oyster Creek is 23 feet above sea level, while the maximum recorded high tide on the Barnegat Bay beachfront 5 miles away is 7 feet above sea level The NRC requires all nuclear plants in the US to be able to withstand the most severe natural phenomena historically reported for each plant’s surrounding area, with a significant margin for uncertainty Tsunami Flood Earthquake |
31 Exelon Nuclear Fleet Overview - IL Plant Location Type/ Containment Water Body License Extension Status / License Expiration (1) Ownership Spent Fuel Storage/ Date to lose full core discharge capacity (2) Braidwood, IL (Units 1 and 2) PWR Concrete/Steel Lined Kankakee River Expect to file application in 2013/ 2026, 2027 100% Dry Cask (Summer 2011) Byron, IL (Units 1 and 2) PWR Concrete/Steel Lined Rock River Expect to file application in 2013/ 2024, 2026 100% Dry Cask Clinton, IL (Unit 1) BWR Concrete/Steel Lined Clinton Lake 2026 100% 2018 Dresden, IL (Units 2 and 3) BWR Steel Vessel Kankakee River Renewed / 2029, 2031 100% Dry cask LaSalle, IL (Units 1 and 2) BWR Concrete/Steel Lined Illinois River 2022, 2023 100% Dry Cask Quad Cities, IL (Units 1 and 2) BWR Steel Vessel Mississippi River Renewed / 2032 75% Exelon, 25% Mid-American Holdings Dry cask (1) Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review. (2) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools. Exelon pursues license extensions well in advance of expiration to ensure adequate time for review by the NRC |
32 Exelon Nuclear Fleet Overview – PA and NJ Plant, Location Type, Containment Water Body License Extension Status / License Expiration (1) Ownership Spent Fuel Storage/ Date to lose full core discharge capacity (2) Limerick, PA (Units 1 and 2) BWR Concrete/Steel Lined Schuylkill River Expect to file application in 2011/ 2024, 2029 100% Dry cask Oyster Creek, NJ (Unit 1) BWR Steel Vessel Barnegat Bay Renewed / 2029 (3) 100% Dry cask Peach Bottom, PA (Units 2 and 3) BWR Steel Vessel Susquehanna River Renewed / 2033, 2034 50% Exelon, 50% PSEG Dry cask TMI, PA (Unit 1) PWR Concrete/Steel Lined Susquehanna River Renewed / 2034 100% 2023 Salem, NJ (Units 1 and 2) PWR Concrete/Steel Lined Delaware River In process (decision in 2011- 2012) / 2016, 2020 42.6% Exelon, 57.4% PSEG Dry Cask (1) Operating license renewal process takes approximately 4-5 years from commencement until completion of NRC review. (2) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to losing full core discharge capacity in their on-site storage pools. (3) On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. The current NRC license for Oyster Creek expires in 2029. Exelon pursues license extensions well in advance of expiration to ensure adequate time for review by the NRC |
33 33 33 ComEd 2010 Rate Case Update ComEd Reply Brief (2/23/11) $343M increase requested 11.50% ROE / 47.28% equity ratio Rate base $7,349M 2009 test year with pro forma plant additions through 6/30/11 ICC Staff Reply Brief Position (2/23/11) $113M increase proposed 10.00% ROE / 47.11% equity ratio Rate base $6,480M Pro forma plant additions and depreciation reserve through 12/31/10 ALJ Proposed Order (4/1/11) $152M increase proposed (after correcting ~$14M calculation error) 10.50% ROE / 47.28% equity ratio Rate base $6,629M Pro forma plant additions and depreciation reserve through 12/31/10 with very limited exceptions (ICC Docket No. 10-0467) Illinois Commerce Commission Final Order will be issued by May 31 |
34 34 ComEd – Proposed Infrastructure Investment and Modernization Legislation Proposed Grid Modernization Legislation Key Concepts Incremental investment of $2.6B of capital over 10 years • $1.5B smart grid/smart meter • $1.1B infrastructure improvements Incorporates an annual formula rate proceeding, similar to FERC Transmission rate • Protocols clarify treatment of several significant items, including pension costs and pension asset • ROE formula based on average 30-year Treasury yield Reduces proceeding timeframe from 11 months to less than 9 months ComEd is driving innovative regulatory and legislative strategy to benefit customers, improve the transparency of the ratemaking process and enable economic development |
35 PECO Procurement Plan (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 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 80 MW of baseload (24x7) block energy product (for Jan-Dec 2012) 70 MW of Jun-Aug 2011 summer on-peak block energy product 40 MW of Dec 2011-Feb 2012 winter on-peak block energy product Large Commercial and Industrial - Hourly 36% of Hourly Full requirements product (Jun 2011-May 2012) (3) May 2, 2011 RFP - Fifth in a series of nine procurements for the PUC- approved Default Service Plan Spring 2011 RFP to be held on May 2, 2011, with results public 15 days thereafter |
36 36 ComEd Customer Usage Breakdown |
37 PECO Customer Usage Breakdown |
38 Sufficient Liquidity (1) Excludes 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. |
39 Key Credit Metrics 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 2009A 2010A 2011E ExGen/Corp ComEd PECO Exelon 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 2009A 2010A 2011E ExGen/Corp ComEd PECO Exelon FFO / Debt (1) (1) See slide 40 for reconciliations to GAAP. (2) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of April 21, 2011. (3) FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp. Moody’s Credit Ratings (2) S&P Credit Ratings (2) Fitch Credit Ratings (2) FFO / Debt Target Range (2) Exelon: Baa1 BBB- BBB+ ComEd: Baa1 A- BBB+ 15-18% PECO: A1 A- A 15-18% Generation: A3 BBB BBB+ 30-35% (3) Interest Coverage (1) 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2009A 2010A 2011E ExGen/Corp ComEd PECO Exelon Debt / Cap (1) |
40 Exelon Consolidated Metric Calculations and Ratios Exelon 2010 YE Adjustments FFO Calculation 2010 YE Source - 2010 Form 10-K (.pdf version) Net Cash Flows provided by Operating Activities 5,244 Pg 159 - Stmt. of Cash Flows +/- Change in Working Capital 644 Pg 159 - Stmt. of Cash Flows (1) - PECO Transition Bond Principal Paydown (392) Pg 174 - Stmt. of Cash Flows (2) + PPA Depreciation Adjustment 207 Pg 295 - Commitments and Contingencies (3) +/- Pension/OPEB Contribution Normalization 448 Pg 268-269 - Post-retirement Benefits (4) + Operating Lease Depreciation Adjustment 35 Pg 299 - Commitments and Contingencies (5) +/- Decommissioning activity (143) Pg 159- Stmt. of Cash Flows +/- Other Minor FFO Adjustments (6) (54) = FFO (a) 5,989 Debt Calculation Long-term Debt (incl. Current Maturities and A/R agreement) 12,828 Pg 161 - Balance Sheet Short-term debt (incl. Notes Payable / Commercial Paper) - Pg 161 - Balance Sheet - PECO Transition Bond Principal Paydown - N/A - no debt outstanding at year-end + PPA Imputed Debt 1,680 Pg 295 - Commitments and Contingencies (7) + Pension/OPEB Imputed Debt 3,825 Pg 268 - Post-retirement benefits (8) + Operating Lease Imputed Debt 428 Pg 299 - Commitments and Contingencies (9) + Asset Retirement Obligation - Pg 261-267 - Asset Retirement Obligations (10) +/- Other Minor Debt Equivalents (11) 84 = Adjusted Debt (b) 18,845 Interest Calculation Net Interest Expense 817 Pg 158 - Statement of Operations - PECO Transition Bond Interest Expense (22) Pg 182 - Significant Accounting Policies + Interest on Present Value (PV) of Operating Leases 29 Pg 299 - Commitments and Contingencies (12) + Interest on PV of Purchased Power Agreements (PPAs) 99 Pg 295 - Commitments and Contingencies (13) +/- Other Minor Interest Adjustments (14) 37 = Adjusted Interest (c) 960 Equity Calculation Total Equity 13,563 Pg 161 - Balance Sheet + Preferred Securities of Subsidaries 87 Pg 161 - Balance Sheet +/- Other Minor Equity Equivalents (15) 111 = Adjusted Equity (d) 13,761 (1) Includes changes in A/R, Inventories, A/P and other accrued expenses, option premiums, counterparty collateral and income taxes. Impact to FFO is opposite of impact to cash flow (2) Reflects retirement of variable interest entity + change in restricted cash (3) Reflects net capacity payment – interest on PV of PPAs (using weighted average cost of debt) (4) Reflects employer contributions – (service costs + interest costs + expected return on assets), net of taxes at 35% (5) Reflects operating lease payments – interest on PV of future operating lease payments (using weighted average cost of debt) (6) Includes AFUDC / capitalized interest (7) Reflects PV of net capacity purchases (using weighted average cost of debt) $ in millions (8) Reflects unfunded status, net of taxes at 35% (9) Reflects PV of minimum future operating lease payments (using weighted average cost of debt) (10) Nuclear decommissioning trust fund balance > asset retirement obligation. No debt imputed (11) Includes accrued interest less securities qualifying for hybrid treatment (50% debt / 50% equity) (12) Reflects interest on PV of minimum future operating lease payments (using weighted average cost of debt) (13) Reflects interest on PV of PPAs (using weighted average cost of debt) (14) Includes AFUDC / capitalized interest and interest on securities qualifying for hybrid treatment (50% debt / 50% equity) (15) Includes interest on securities qualifying for hybrid treatment (50% debt / 50% equity) FFO / Debt Coverage = FFO (a) Adjusted Debt (b) FFO Interest Coverage = FFO (a) + Adjusted Interest (c) Adjusted Interest (c) Adjusted Capitalization (e) = Adjusted Debt (b) + Adjusted Equity (d) = 32,606 Rating Agency Debt Ratio = Adjusted Debt (b) Adjusted Capitalization (e) 32% 7.2x 58% = = = 2010A Credit Metrics |
41 1Q GAAP EPS Reconciliation Three Months Ended March 31, 2011 ExGen ComEd PECO Other Exelon 2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.90 $0.11 $0.19 $(0.03) $1.17 Mark-to-market impact of economic hedging activities (0.14) - - - (0.14) Unrealized gains related to nuclear decommissioning trust funds 0.04 - - - 0.04 Retirement of fossil generating units (0.02) - - - (0.02) Non-cash charge resulting from Illinois tax rate change legislation (0.03) (0.01) - - (0.04) 1Q 2011 GAAP Earnings (Loss) Per Share $0.75 $0.10 $0.19 $(0.03) $1.01 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended March 31, 2010 ExGen ComEd PECO Other Exelon 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.66 $0.19 $0.17 $(0.02) $1.00 Mark-to-market impact of economic hedging activities 0.21 - - - 0.21 Unrealized gains related to nuclear decommissioning trust funds 0.03 - - - 0.03 Retirement of fossil generating units (0.01) - - - (0.01) Non-cash charge resulting from health care legislation (0.04) (0.02) (0.02) (0.02) (0.10) 1Q 2010 GAAP Earnings (Loss) Per Share $0.85 $0.17 $0.15 $(0.04) $1.13 |
42 GAAP to Operating Adjustments Exelon’s 2011 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 • Any changes in decommissioning obligation estimates • Non-cash charge to remeasure deferred taxes at higher Illinois corporate tax rates • Financial impacts associated with the planned retirement of fossil generating units • Other unusual items • Significant changes to GAAP Operating earnings guidance assumes normal weather for remainder of the year |