Earnings Conference Call 4 th Quarter 2011 January 25, 2012 Exhibit 99.2 |
Cautionary Statements Regarding Forward-Looking Information 2 Except for the historical information contained herein, certain of the matters discussed in this communication constitute “forward- looking statements” within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, both as amended by the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “target,” “forecast,” and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding benefits of the proposed merger of Exelon Corporation (Exelon) and Constellation Energy Group, Inc. (Constellation), integration plans and expected synergies, the expected timing of completion of the transaction, anticipated future financial and operating performance and results, including estimates for growth. These statements are based on the current expectations of management of Exelon and Constellation, as applicable. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication regarding the proposed merger. For example, (1) the companies may be unable to obtain regulatory approvals required for the merger, or required regulatory approvals may delay the merger or result in the imposition of conditions that could have a material adverse effect on the combined company or cause the companies to abandon the merger; (2) conditions to the closing of the merger may not be satisfied; (3) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (4) problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; (5) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (6) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (7) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (8) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (9) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (10) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (11) the companies may be adversely affected by other economic, business, and/or competitive factors. Other unknown or unpredictable factors could also have material adverse effects on future results, performance or achievements of Exelon, Constellation or the combined company. |
Cautionary Statements Regarding Forward-Looking Information (Continued) 3 Discussions of some of these other important factors and assumptions are contained in Exelon’s and Constellation’s respective filings with the Securities and Exchange Commission (SEC), and available at the SEC’s website at www.sec.gov, including: (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 Quarterly Report on Form 10-Q for the quarterly period ended September 30, 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 13; (3) Constellation’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 12; and (4) Constellation’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 in (a) Part II, Other Information, ITEM 1A. Risk Factors and ITEM 5. Other Information, (b) Part I, 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: Notes to Consolidated Financial Statements, Commitments and Contingencies. These risks, as well as other risks associated with the proposed merger, are more fully discussed in the definitive joint proxy statement/prospectus included in the Registration Statement on Form S-4 that Exelon filed with the SEC and that the SEC declared effective on October 11, 2011 in connection with the proposed merger. In light of these risks, uncertainties, assumptions and factors, the forward-looking events discussed in this communication may not occur. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this communication. Neither Exelon nor Constellation undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this communication. In connection with the proposed merger between Exelon and Constellation, Exelon filed with the SEC a Registration Statement on Form S-4 that included the definitive joint proxy statement/prospectus. The Registration Statement was declared effective by the SEC on October 11, 2011. Exelon and Constellation mailed the definitive joint proxy statement/prospectus to their respective security holders on or about October 12, 2011. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY CONTAIN IMPORTANT INFORMATION about Exelon, Constellation and the proposed merger. Investors and security holders may obtain copies of all documents filed with the SEC free of charge at the SEC's website, www.sec.gov. In addition, a copy of the definitive joint proxy statement/prospectus may be obtained free of charge from Exelon Corporation, Investor Relations, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Constellation Energy Group, Inc., Investor Relations, 100 Constellation Way, Suite 600C, Baltimore, MD 21202. Additional Information and Where to Find it |
2011: Year In Review 4 Financial Success Q4 operating EPS of $0.82 per share 2011 operating EPS of $4.16 per share and above original expectations Strategic Execution Acquired Wolf Hollow CCGT in Texas and AVSR 1 Solar PV facility in California Nuclear uprate program added 138.6 MW in 2011 Exelon Wind added 90 MW in 2011 2011 was a year of exemplary financial and operating performance, constructive regulatory environment and solid execution on strategic initiatives |
EPA: Clean Air Standards 5 Final rules substantially similar to proposed rules; no significant changes to standards for existing units Rule provides sufficient flexibility for compliance • Compliance timeline is three years • Some units will be granted a 1 year extension on a case by case basis PJM coal plant retirement estimate unchanged by final rule • Expect rule to lead to the retirement of 15 GW of coal capacity Rule to be implemented in early 2015 D.C. Court of Appeals granted a stay on the Cross State Air Pollution Rule (CSAPR) Court’s recent order demonstrates commitment to resolve this case on an expedited basis CSAPR is not a major driver of coal plant retirements, as demonstrated by EPA modeling Minimal impact to Exelon’s 2012 gross margin as generation position in PJM is well hedged Air Toxics Rule Cross State Air Pollution Rule • Final briefs due by March 16 th 2012 • Oral arguments on April 13 th 2012 Air Toxics Rule is still expected to be the more impactful rule to drive coal plant retirements, and we continue to believe the CSAPR is valid |
Merger Approvals Process on Schedule (as of 1/20/2012) 6 Note: The Department of Public Utilities in Massachusetts concluded on September 26, 2011 that it does not have jurisdiction over the merger. Stakeholder Status of Key Milestones Approved Texas PUC (Case No. 39413) Approval received on August 3, 2011 Securities and Exchange Commission (SEC) (File No. 333-175162) Joint proxy statement declared effective on October 11, 2011 Shareholder Approval Shareholders overwhelmingly approved the merger on November 17, 2011 New York PSC (Case No. 11–E–0245) Declaratory ruling on December 15, 2011 confirming that Commission review is not required Department of Justice (DOJ) U.S. DOJ clearance received on December 21, 2011 Nuclear Regulatory Commission (Docket Nos. 50-317, 50-318, 50-220, 50-410, 50-244, 72-8, 72-67) Filed for indirect transfer of Constellation Energy licenses on May 12, 2011 Federal Energy Regulatory Commission (FERC) (Docket No. EC 11-83) Settlement agreement filed with PJM Market Monitor on October 11, 2011 Maryland PSC (Case No. 9271) Settlement agreement reached with key stakeholders in Maryland on December 15, 2011 Hearings scheduled for January 25 – 27, 2012 Briefs due February 6, 2012 Order expected on February 17, 2012 |
7 Key Financial Messages Q4 2011 operating earnings of $0.82 per share Full year 2011 operating earnings of $4.16 per share Strong cash flow from operations Credit metrics above target range across all operating companies Disciplined execution of ratable hedge program continues to create value Note: 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 Exelon Generation Operating EPS Contribution $2.91 $0.81 $3.01 $0.54 Full Year 4Q 2011 2010 Outage Days (3) 4Q10 4Q11 Refueling 97 103 Non-refueling 18 11 Favorable market/portfolio conditions: $0.06 (2) Unfavorable capacity pricing: $(0.13) Higher O&M costs, including refueling costs at Salem: $(0.08) Increased planned nuclear refueling costs: $(0.02) Higher nuclear fuel costs: $(0.02) Higher depreciation expense: $(0.02) Nuclear volume: $(0.01) Key Drivers – 4Q11 vs. 4Q10 (1) (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) Favorable market/portfolio conditions includes: $0.03 higher realized prices in the Mid-Atlantic net of lower realized prices in the Midwest, $0.02 Wind and $0.01 Hydro volume. (3) Outage days exclude Salem. |
9 ComEd Operating EPS Contribution $0.68 $0.13 $0.61 $0.18 Full Year 4Q 2011 2010 4Q10 Actual 4Q11 Actual Normal Heating Degree-Days 2,292 1,832 2,278 Cooling Degree-Days 15 14 7 Energy Infrastructure Modernization Act, net (2) : $0.06 Electric distribution rates: $0.03 Higher O&M costs: $(0.04) Weather: $(0.01) Key Drivers – 4Q11 vs. 4Q10 (1) (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) O&M impacts include credit for the allowed recovery of certain 2011 storm costs, partially offset by a one-time contribution. |
10 PECO 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. Note: CTC = Competitive Transition Charge $0.54 $0.03 $0.58 $0.11 Full Year 4Q 2010 2011 4Q10 Actual 4Q11 Actual Normal Heating Degree-Days 1,686 1,302 1,634 Cooling Degree-Days 19 14 21 2010 CTC amortization expense, net of collections: $0.07 Electric and gas distribution rates: $0.04 Weather: $(0.04) Key Drivers – 4Q11 vs. 4Q10 (1) |
11 2011 Actual Sources and Uses of Cash (1) Excludes counterparty collateral activity. (2) Cash Flow from Operations primarily includes net cash flows provided by operating activities, replacement of credit facilities and net cash flows used in investing activities other than capital expenditures. (3) 2011 dividend of $2.10/share. Dividends are subject to declaration by the Board of Directors. (4) Includes $350 million in Nuclear Uprates and $250 million for Exelon Wind spend. (5) Represents new business, smart grid/smart meter investment and transmission growth projects. (6) Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through August 31, 2012. (7) “Other” includes proceeds from options and expected changes in short-term debt. (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities. ($ millions) Exelon (8) Beginning Cash Balance (1) $800 Cash Flow from Operations (2) 800 800 3,475 4,975 CapEx (excluding Nuclear Fuel, Nuclear Uprates, Exelon Wind and Utility Growth CapEx) (750) (350) (825) (1,975) Nuclear Fuel n/a n/a (1,075) (1,075) Dividend (3) (1,400) Nuclear Uprates and Exelon Wind (4) n/a n/a (600) (600) Wolf Hollow Acquisition n/a n/a (300) (300) Antelope Valley Solar Ranch One Acquisition n/a n/a (75) (75) Utility Growth CapEx (5) (275) (125) n/a (400) Net Financing (excluding Dividend): Debt Issuances (6) 1,200 -- -- 1,200 Debt Retirements (550) (250) -- (800) Other (7) -- (50) 25 200 Ending Cash Balance (1) $550 |
Post-Merger Legal Entity Structure BGE • BGE will exist as a separate subsidiary under Exelon with its current ring-fenced structure • BGE will continue as a separate SEC registrant and will continue to issue Constellation Energy Group, Inc. (CEG) will be merged into Exelon Corporation • CEG subsidiaries, excluding BGE, will then be transferred to Exelon Generation and become direct wholly-owned subsidiaries of Exelon Generation • Exelon Corporation will assume the obligations of CEG’s publicly-held debt, guarantees and other contracts Benefits of merging CEG into Exelon • Placement at HoldCo provides bondholders with diversity of cash flows from regulated and unregulated businesses • Optimizes funding costs by utilizing the Exelon Generation credit as the primary financing vehicle for the unregulated business post-merger • Simplifies accounting and reporting through elimination of separate CEG SEC registrant • No impacts on BGE ring-fencing commitments to Maryland PSC 12 |
Exelon Generation Hedging Program Percentage of Expected Generation Hedged Being close to fully hedged in 2012 has protected us from the recent decline in power prices 0% 20% 40% 60% 80% 100% 2014 2013 2012 Ratable % Hedged without Options Option % 2012 Gross Margin Comparison (1) 4,450 5,150 3,500 4,000 4,500 5,000 5,500 6,000 6,500 5,965 09/30/2011 5,975 12/31/2011 2012 Hedged Gross Margin ($ millions) 2012 Open Gross Margin 13 (1) Gross Margin estimates are rounded. Open Gross Margin assumes no hedges. |
Exelon Generation Hedging Program As a consequence of being ahead of a ratable pace in 2009 and 2010 in the PJM portfolio we were able to capture higher market prices and be selective in 2011 by holding off on sales when prices were low. 2012 Midwest & Mid-Atlantic Hedging Over the Past Three Years 2012 South & West Hedging Over the Past Three Years We have consciously kept more open length in the South and West region to benefit from increased heat rates and volatility in the ERCOT market and are well positioned to capture upside in the spot market. $54.73 0% 20% 40% 60% 80% 100% $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 2011 2010 2009 West Hub 2012 ATC Avg Yearly Price Ratable 2012 Year End Hedge % 9.98 0% 20% 40% 60% 80% 100% 8.40 8.60 8.80 9.00 9.20 9.40 9.60 9.80 10.00 10.20 2011 2010 2009 ERCOT North 2012 On Peak Yearly Avg Heat Rate Ratable 2012 Year End Hedge % 14 $45.68 $44.91 8.75 8.91 While our three-year ratable hedging program ensures stable cash flows, we continue to use our market views to create incremental value via timing, product and regional allocations of sales |
15 John Rowe’s Key Accomplishments • Unicom/PECO merger Creating Exelon • Running nuclear plants at world-class levels Turning Around Nuclear • Vision for a cleaner, more competitive future Selling ComEd’s Fossil Fleet • Letting competitive markets work Separating Generation • Keeping the lights on Improving ComEd’s Service • Smooth transition to competitive market, starting with the 2007 settlement Promoting Competition in Illinois • Environmental strategy committed to clean generation Launching Exelon 2020 • Maintaining a solid regulatory relationship Making Pennsylvania Proud • PECO’s rate settlement and ComEd’s infrastructure legislation Regulatory Outcomes • Cost management, risk management Maintaining Financial Discipline |
Exelon Generation Hedging Disclosures (as of December 31, 2011) 16 |
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 December 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. |
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, operating 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 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 operating 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 2012 2013 2014 Estimated Open Gross Margin ($ millions) (1)(2) $4,450 $4,950 $5,400 Reference Prices (1) Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (3) $3.24 $29.77 $38.86 $7.29 $3.94 $31.44 $41.26 $6.37 $4.34 $33.15 $43.97 $5.22 Exelon Generation Open Gross Margin and Reference Prices (1) Based on December 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, $2.50 variable O&M. |
21 2012 2013 2014 Expected Generation (GWh) (1) 173,100 167,600 166,100 Midwest 99,200 95,800 95,400 Mid-Atlantic 56,800 56,100 55,700 South & West 17,100 15,700 15,000 Percentage of Expected Generation Hedged (2) 88-91% 61-64% 32-35% Midwest 89-92 62-65 30-33 Mid-Atlantic 94-97 66-69 33-36 South & West 65-68 43-46 34-37 Effective Realized Energy Price ($/MWh) (3) Midwest $40.50 $40.00 $37.50 Mid-Atlantic $50.50 $50.50 $51.00 South & West $2.00 $3.00 $2.00 Generation Profile (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 10 refueling outages in 2012 and 2013 and 11 refueling outages in 2014 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.5%, 93.3% and 93.4% in 2012, 2013 and 2014 at Exelon-operated nuclear plants. These estimates of expected generation in 2012, 2013 and 2014 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
22 Gross Margin Sensitivities with Existing Hedges ($ 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% 2012 $20 $(5) $40 $(30) $15 $(15) +/- $35 2013 $260 $(230) $185 $(180) $115 $(110) +/- $40 2014 $600 $(560) $335 $(330) $205 $(205) +/- $40 Exelon Generation Gross Margin Sensitivities (with Existing Hedges) (1) Based on December 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. |
23 95% case 5% case $5,300 $6,100 $5,800 $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 2012 2013 2014 $7,000 $4,600 (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 , 2013 and 2014 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 December 31, 2011. |
24 Midwest Mid-Atlantic South & West Step 1 Start with fleetwide open gross margin $4.45 billion Step 2 Determine the mark-to-market value of energy hedges 99,200GWh * 90% * ($40.50/MWh-$29.77MWh) = $0.96 billion 56,800GWh * 94% * ($50.50/MWh-$38.86MWh) = $0.62 billion 17,100GWh * 66% * ($2.00/MWh-$7.29MWh) = $(0.06) billion Step 3 Estimate hedged gross margin by adding open gross margin to mark-to- market value of energy hedges Open gross margin: $4.45 billion MTM value of energy hedges: $0.96billion + $0.62billion + $(0.06) billion Estimated hedged gross margin: $5.97 billion Illustrative Example of Modeling Exelon Generation 2012 Gross Margin (with Existing Hedges) |
20 25 30 35 40 45 50 55 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 30 35 40 45 50 55 60 65 70 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 3.0 3.5 4.0 4.5 5.0 5.5 6.0 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 65 70 75 80 85 90 95 100 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 Market Price Snapshot Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West and Ni-Hub Wrap Forward Prices 2014 $4.01 2013 $3.53 Forward NYMEX Coal 2014 $72.69 2013 $68.44 2013 Ni-Hub $33.58 2014 Ni-Hub $35.73 2014 PJM-West $44.85 2013 PJM-West $42.15 2013 Ni-Hub $23.04 2014 Ni-Hub $24.05 2014 PJM-West $33.28 2013 PJM-West $31.07 25 Rolling 12 months, as of January 18 th 2012. Source: OTC quotes and electronic trading system. Quotes are daily. |
6 7 8 9 10 11 12 13 14 15 16 17 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 8.6 8.8 9.0 9.2 9.4 9.6 9.8 10.0 10.2 10.4 10.6 10.8 11.0 11.2 11.4 11.6 11.8 12.0 12.2 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 35 40 45 50 55 60 65 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 Market Price Snapshot 2014 10.88 2013 11.52 2013 $40.11 2014 $43.10 2013 $3.48 2014 $3.96 Houston Ship Channel Natural Gas Forward Prices ERCOT North On-Peak Forward Prices ERCOT North On-Peak v. Houston Ship Channel Implied Heat Rate 2013 $12.47 2014 $12.00 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder 26 Rolling 12 months, as of January 18 th 2012. Source: OTC quotes and electronic trading system. Quotes are daily. |
27 Appendix |
2011 results were achieved in a very challenging market environment due to effectiveness of asset allocations and hedging strategy • Decreased equity investments and increased investment in fixed income securities and alternative investments • The liability hedge has offset more than 50% of the pension liability increase caused by lower interest rates Pension plans are 83% funded as of December 31, 2011 Pension Funds Performance Exelon’s pension investment strategy has effectively dampened the volatility of plan assets and plan funded status 28 S&P 500 Exelon Pension Assets 2.1% 9.8% 2011 Actual Returns |
29 Exelon Generation 2011 EPS Contribution $ / Share $ 3.01 $ (0.03) $ (0.01) $ (0.08) $ (0.26) $ 0.49 $ 2.91 Other RNF 2010A O&M 2011A Key Items: Expiration of PECO PPA $0.62 Market/portfolio conditions (1) $0.25 Unfavorable capacity pricing ($0.23) Nuclear Fuel ($0.08) Transmission Upgrades (2) ($0.06) Key Items: Inflation ($0.08) Nuclear Outages ($0.05) Exelon Wind ($0.04) Higher refueling costs at Salem ($0.02) Depreciation & Amortization Interest Expense (1) Includes $0.15 of favorable market and portfolio conditions in the South and $0.07 related to Exelon Wind. (2) Reflects intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon. |
30 ComEd 2011 EPS Contribution $ / Share 30 $ 0.61 $ (0.02) $ (0.02) $ (0.02) $ (0.14) $ 0.13 $ 0.68 2011A Other O&M RNF 2010A Key Items: Distribution Revenue (1) $0.08 Formula Rate Legislation (2) $0.03 Transmission Revenue $0.02 Weather ($0.02) Key Items: 2010 Bad Debt Recovery (3) ($0.06) Inflation ($0.03) One-time contribution (4) ($0.01) Storm costs (5) ($0.01) 2010 Distribution Rate Case Order $0.02 (1) Increased distribution revenue pursuant to the 2011 electric distribution rate case order, effective June 1, 2011. (2) Increased distribution revenues as a result of the annual true-up in the performance based formula rate tariff pursuant to the Energy Infrastructure Modernization Act (EIMA). (3) Reflects a 2010 credit for the recovery of 2008 and 2009 bad debt expense pursuant to the ICC's February 2010 approval of a bad debt rider, partially offset by a contribution mandated by Illinois legislation. (4) Represents a one-time contribution to a new Science and Technology Innovation Trust accrued pursuant to EIMA. (5) Includes a $0.04 credit for the allowed recovery of certain 2011 storm costs, net of amortization expense. Depreciation & Amortization Interest Expense |
31 PECO 2011 EPS Contribution $ / Share $ 0.58 $ 0.04 $ 0.03 $ (0.04) $ (0.03) $ (0.05) $ 0.08 $ 0.54 2011A Other Taxes CTC, net O&M RNF 2010A Key Items: Electric & Gas Distribution Rate (1) $0.15 Weather ($0.05) Key Items: Storm costs ($0.01) Inflation ($0.02) (1) Reflects increased distribution revenue pursuant to the 2010 Pennsylvania electric and natural gas distribution rate case settlements effective January 1, 2011. (2) Includes associated gross receipts taxes. Key Items: Revenue net of amortization (2) ($0.06) Interest on PECO transition $0.02 bonds Key Items: T&D tax repairs deductions $0.05 Depreciation & Amortization |
ComEd Load Trends -3% -2% -1% 0% 1% 2% 3% 3Q11 2Q11 1Q11 4Q12 3Q12 2Q12 1Q12 4Q11 Residential Gross Metro Product All Customer Classes Large C&I Note: C&I = Commercial & Industrial Chicago U.S. Unemployment rate (1) 10.5% 8.5% 2011 annualized growth in gross domestic/metro product (2) 1.7% 1.8% (1) Source: U.S. Dept. of Labor (December 2011) and Illinois Department of Security (November 2011) (2) Source: Global Insight (November 2011) (3) Not adjusted for leap year 4Q11 2011 2012E (3) Average Customer Growth 0.3% 0.4% 0.4% Average Use-Per-Customer 0.9% (1.7)% (1.0)% Total Residential 1.2% (1.3)% (0.6)% Small C&I (1.2)% (0.8)% 0.0% Large C&I 1.8% 0.6% (0.2)% All Customer Classes 0.4% (0.5)% (0.2)% 32 Weather-Normalized Load Year-over-Year Key Economic Indicators Weather-Normalized Load |
PECO Load Trends Note: C&I = Commercial & Industrial -12.5% -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 4Q12 3Q12 2Q12 1Q12 4Q11 3Q11 2Q11 1Q11 Gross Metro Product Residential Large C&I All Customer Classes Philadelphia U.S. Unemployment rate (1) 7.9% 8.5% 2011 annualized growth in gross domestic/metro product (2) 0.9% 1.8% (1) Source: U.S. Dept. of Labor data (December 2011) – US U.S. Dept. of Labor prelim. data (November 2011) – Philadelphia (2) Source: Global Insight (November 2011) (3) Not adjusted for leap year 4Q11 2011 2012E (3) Average Customer Growth 0.3% 0.3% 0.4% Average Use-Per-Customer 0.9% 1.3% (2.5)% Total Residential 1.1% 1.7% (2.2)% Small C&I 0.3% (0.7)% (1.7)% Large C&I (6.8)% (3.3)% (10.5)% All Customer Classes (2.2)% (0.9)% (5.4)% Large C&I (excluding refinery impact) Oil refinery closing estimated impact to reduce Large C&I and total load in 2012 by 9.1% and 3.7%, respectively 33 Weather-Normalized Load Year-over-Year Key Economic Indicators Weather-Normalized Load |
Maryland Settlement Summary 34 Settlement agreement with State of Maryland, City of Baltimore and other key parties increases value of merger package to more than $1 billion Package includes 285 – 300 MW of new generation in Maryland • 120 MW of natural gas generation • 125 MW of Tier 1 renewable generation, of which at least 62.5 MW will be wind generation • 30 MW of solar energy • 10 - 25 MW of generation capacity from poultry litter Significant benefits to the state and customers • $100 credit to each residential customer • Construction of LEED office building in Baltimore • $50M funding for low income weatherization measures • $32M funding for offshore wind research and development in Maryland Commitments to preserve BGE as a leading Maryland company • Maintain capital and O&M spend and no dividend contributions to parent through 2014 • Maintain investment in smart meters, reliability and other key initiatives |
35 Exelon Dividend Exelon’s Board of Directors approved a contingent stub dividend for Exelon shareholders of $0.00583/share per day for Q2 2012 in anticipation of the merger close ($0.525/share for the quarter) Stub dividend declaration ensures that Exelon shareholders continue to receive all dividends at the current $2.10 per share annualized rate Pre- and post-close stub dividends must be declared separately to account for Constellation shareholders becoming Exelon shareholders at merger close Assuming a February 29, 2012 close for illustrative purposes only: (1) Assuming a 2/29/2012 merger close; for Exelon shareholders, Q2 2012 dividend will be based on a per diem rate of $0.00583 ($0.525 divided by 90 days). (2) Future dividend, following the stub dividend, is subject to approval by the Board of Directors. $0.525 Record Date Payment Date Dividend Type Per Share Amount 2/15/2011 3/9/2011 Regular Dividend $0.525 2/28/2012 3/28/2012 Pre- close Stub Dividend (1) $0.076 5/15/2012 6/8/2012 Post- close Stub Dividend (1) $0.449 8/15/2012 9/10/2012 Regular Dividend (2) $0.525 11/15/2012 12/10/2012 Regular Dividend (2) $0.525 Current Exelon shareholders will continue to receive a total dividend of $0.525 per quarter |
36 Constellation Energy’s Board of Directors approved a contingent stub dividend for Constellation shareholders of $0.00264/share per day for Q1 2012 in anticipation of merger close Stub dividend declaration ensures that Constellation shareholders continue to receive their existing quarterly dividend rate prior to the merger, and benefit from the Exelon annualized dividend rate ($2.10 per share) beginning on the day the merger closes Pre- and post-close stub dividends must be declared separately to account for Constellation shareholders becoming Exelon shareholders at merger close Assuming a February 29, 2012 close for illustrative purposes only : (1) Assuming a 2/29/2012 merger close, Q1 2012 dividend will be based on a per diem rate of $0.00264 ($0.24 divided by 91 days). Post-close Exelon Q2 2012 stub dividend will be based on a per diem rate of $0.00583. (2) Assuming a 2/29/2012 merger close, Constellation shareholders will start receiving the full quarterly Exelon dividend of $0.525 per share in Q3 2012. Future dividend, following the stub dividend, is subject to approval by the Board of Directors. Constellation Dividend Record Date Payment Date Dividend Type Per Share Amount 12/12/2011 1/3/2012 Regular CEG Dividend $0.24 2/28/2012 3/28/2012 Pre- close CEG Stub Dividend (1) $0.206 5/15/2012 6/8/2012 Post- close EXC Stub Dividend (1) $0.449 8/15/2012 9/10/2012 Regular EXC Dividend (2) $0.525 11/15/2012 12/10/2012 Regular Dividend (2) $0.525 Constellation shareholders will receive the Exelon dividend rate upon merger close |
37 ComEd – Regulatory Schedule for 2012 Q1 Q2 Q3 Q4 Initial filing with ICC (11/8/11) Proposed order (around 5/1); Final order (by 5/31) Procurements for ATC supply and RECs for 6/1/13- 12/31/17 (by end of February) Q4 2011 Distribution Formula Rate (Docket # 11-0721) Performance Metrics (Docket # 11-0772) Illinois Power Agency Procurement Transmission Rate Update Annual update filing with FERC (5/15) Rates effective (June 2012 thru May 2013) Rates effective June thru Dec. Filing with ICC (12/8/11) Final order (by 4/6) Second filing with ICC (by 5/1) Rates effective Jan. thru Dec. Regular annual procurement event (Spring) Note: ICC = Illinois Commerce Commission; FERC = Federal Energy Regulatory Commission; ATC = around-the-clock; REC = renewable energy credit Final order (by 12/27) Annual updates (by 6/1) 2013 |
38 PECO – Default Service Plan Filing (DSP II) (1) FR = Full Requirements; (2) FPFR = Fixed-Price Full Requirements Proposed Procurement Mix Class DSP I (1/1/11 – 5/31/13) DSP II (6/1/13 – 5/31/15) Large C&I Current load retained: 4% 100% spot-priced FR (1) products 2011 opt-in FPFR (2) product 100% of supply procured directly from the PJM spot market Medium Commercial Current load retained: 22% 85% 1-year FPFR products, 15% spot-priced FR products 100% 6-month FPFR products Small Commercial Current load retained: 48% 70% 1-year FPFR products, 20% 2-year FPFR products, 10% spot-priced FR products 100% 1-year FPFR products Residential Current load retained: 75% 45% 2-year FPFR products; 30% 1-year FPFR products; targeted 20% block products of 1-yr, 2-yr, 5-yr and seasonal terms; targeted 5% spot market purchases As block products expire, block and spot is replaced by FPFR products with terms ending 5/31/15 (end of DSP II period) Remainder of portfolio is a mix of 2-yr and 1-yr FPFR products, with delivery periods overlapping on a semi- annual basis Filing Schedule: On 1/13/12, PECO filed a new Default Service Plan with the PAPUC, which outlines how PECO will purchase electricity for customers not purchasing from a competitive generation supplier from 6/1/13 through 5/31/15 PAPUC will assign an Administrative Law Judge to set a procedural schedule with a Final Order requested no later than mid-October 2012 Note: PAPUC = Pennsylvania Public Utility Commission Incorporates Retail Market Enhancements suggested by PAPUC Order issued 12/15/11: Offers a 1-year opt-in auction program with price at least 5% less than PECO’s expected Price to Compare as of 6/1/13 Establishes a residential customer referral program to promote the lowest 1-year, fixed price available each month Provides customer information and referral programs for various products; “seamless” moves between properties |
Sufficient Liquidity ($ millions) Exelon (3) Aggregate Bank Commitments (1) $1,000 $600 $5,600 $7,700 Outstanding Facility Draws -- -- -- -- Outstanding Letters of Credit (1) (1) (884) (894) Available Capacity Under Facilities 999 599 4,716 6,806 Outstanding Commercial Paper -- -- -- (136) Available Capacity Less Outstanding Commercial Paper $999 $599 $4,716 $6,670 Exelon bank facilities are largely untapped 39 (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 Exelon Corp’s $500M credit facility, letters of credit and commercial paper outstanding. Available Capacity Under Bank Facilities as of January 17, 2012 (2) |
Key Credit Metrics Moody’s Credit Ratings (2) (3) S&P Credit Ratings (2) (3) Fitch Credit Ratings (2) (3) FFO / Debt Target Range Exelon: Baa1 BBB- BBB+ ComEd: Baa1 A- BBB+ 15-18% PECO: A1 A- A 15-18% Generation: A3 BBB BBB+ 30-35% (4) 10% 20% 30% 40% 50% 60% Exelon PECO ComEd 2011A 2010A 2009A 0X 2X 4X 6X 8X 10X 12X Exelon PECO ComEd 2011A 2010A 2009A 40% 50% 60% 70% 80% Exelon PECO ComEd 2011A 2010A 2009A FFO/Debt (1) Interest Coverage (1) Debt to Cap (1) 40 (1) See slide 41 for reconciliations to GAAP. (2) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of January 20, 2012. (3) Moody’s placed Exelon and Generation under review for a possible downgrade after the proposed merger with Constellation Energy was announced. S&P and Fitch affirmed ratings of Exelon and subsidiaries after the proposed merger was announced. (4) FFO/Debt Target Range reflects Generation FFO/Debt in addition to the debt obligations of Exelon Corp. Range represents FFO/Debt to maintain current ratings at current business risk. ExGen/ Corp ExGen/ Corp ExGen/ Corp |
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) 2010A Credit Metrics 41 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% = = = |
42 4Q GAAP EPS Reconciliation Three Months Ended December 31, 2011 ExGen ComEd PECO Other Exelon 2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.54 $0.18 $0.11 $(0.02) $0.82 Mark-to-market adjustments from economic hedging activities 0.07 - - - 0.07 Unrealized gains related to nuclear decommissioning trust funds 0.07 - - - 0.07 Retirements of fossil generation units (0.01) - - - (0.01) Constellation acquisition costs (0.01) - (0.00) (0.02) (0.03) Non-cash remeasurement of deferred income taxes 0.01 - - (0.02) (0.01) 4Q 2011 GAAP Earnings (Loss) Per Share $0.67 $0.18 $0.11 $(0.05) $0.91 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 December 31, 2010 ExGen ComEd PECO Other Exelon 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.81 $0.13 $0.03 $(0.01) $0.96 Mark-to-market adjustments from economic hedging activities (0.17) - - - (0.17) 2007 Illinois electric rate settlement (0.01) - - - (0.01) Unrealized gains related to nuclear decommissioning trust funds 0.04 - - - 0.04 Retirements of fossil generation units (0.03) - - - (0.03) Exelon Wind acquisition costs (0.01) - - - (0.01) Asset retirement obligation - 0.01 - - 0.01 4Q 2010 GAAP Earnings (Loss) Per Share $0.63 $0.14 $0.03 $(0.01) $0.79 |
43 Full Year GAAP EPS Reconciliation Twelve Months Ended December 31, 2011 ExGen ComEd PECO Other Exelon 2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $3.01 $0.61 $0.58 $(0.05) $4.16 Mark-to-market adjustments from economic hedging activities (0.27) - - - (0.27) Unrealized losses related to nuclear decommissioning trust funds (0.00) - - - (0.00) Retirement of fossil generating units (0.05) - - - (0.05) Asset retirement obligation (0.03) - 0.00 - (0.02) Constellation acquisition costs (0.01) - (0.00) (0.06) (0.07) AVSR 1 acquisition costs (0.01) - - - (0.01) Non-cash charge resulting from Illinois tax rate change legislation (0.03) (0.01) - (0.00) (0.04) Wolf Hollow acquisition 0.03 - - - 0.03 Recovery of costs pursuant to distribution rate case order - 0.03 - - 0.03 Non-cash remeasurement of deferred income taxes 0.01 - - (0.02) (0.01) FY 2011 GAAP Earnings (Loss) Per Share $2.66 $0.63 $0.58 $(0.12) $3.75 Twelve Months Ended December 31, 2010 ExGen ComEd PECO Other Exelon 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $2.91 $0.68 $0.54 $(0.07) $4.06 Mark-to-market adjustments from economic hedging activities 0.08 - - - 0.08 2007 Illinois electric rate settlement (0.02) - - - (0.02) Unrealized gains related to nuclear decommissioning trust funds 0.08 - - - 0.08 Asset retirement obligation - 0.01 - - 0.01 Retirement of fossil generating units (0.08) - - - (0.08) Non-cash remeasurement of income tax uncertainties 0.10 (0.16) (0.03) (0.01) (0.10) Non-cash charge resulting from health care legislation (0.04) (0.02) (0.02) (0.02) (0.10) Emission allowances impairment (0.05) - - - (0.05) Exelon Wind acquisition costs (0.01) - - - (0.01) FY 2010 GAAP Earnings (Loss) Per Share $2.97 $0.51 $0.49 $(0.10) $3.87 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. |