Earnings Conference Call 3 rd Quarter 2011 October 26, 2011 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 shareholder approvals required for the merger; (2) 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; (3) conditions to the closing of the merger may not be satisfied; (4) an unsolicited offer of another company to acquire assets or capital stock of Exelon or Constellation could interfere with the merger; (5) 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; (6) the combined company may be unable to achieve cost-cutting synergies or it may take longer than expected to achieve those synergies; (7) the merger may involve unexpected costs, unexpected liabilities or unexpected delays, or the effects of purchase accounting may be different from the companies’ expectations; (8) the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; (9) the businesses of the companies may suffer as a result of uncertainty surrounding the merger; (10) the companies may not realize the values expected to be obtained for properties expected or required to be divested; (11) the industry may be subject to future regulatory or legislative actions that could adversely affect the companies; and (12) 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. |
3 Cautionary Statements Regarding Forward-Looking Information (Continued) 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 (to be filed on October 26, 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 June 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 |
4 2011 Operating Earnings Guidance 3Q 2011 operating earnings of $1.12 per share • Exceeded guidance range of $1.00 - $1.10 per share for the quarter • Continued operational excellence at Exelon Nuclear with a 95.8% capacity factor • Texas contributed $0.10 per share to third quarter earnings • $(0.08) per share of incremental storm costs at ComEd and PECO compared to 3Q 2010 Reaffirming operating earnings guidance for 2011 of $4.05 - $4.25/share (1) $4.05 - $4.25 $2.95 - $3.10 $0.55 - $0.65 $0.50 - $0.60 $1.12 $0.79 $0.16 $0.17 $1.05 $0.79 $0.13 $0.15 $1.17 $0.90 $0.19 $0.11 HoldCo ExGen PECO ComEd Q1 Actual Q2 Actual Q3 Actual Q4 2011 Guidance (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. (2) Earnings guidance for OpCos may not add up to consolidated EPS guidance. |
5 Exelon Texas Performance in Q3 (1) Includes ERCOT generation from LaPorte, Wolf Hollow, Frontier, Handley and Mountain Creek. PPAs or tolls sold by Exelon are excluded from both generation and capacity. Intermediate 2,210 Peaking 1,262 ERCOT fossil capacity ~ 3,472 MW Our Texas generation assets are well positioned from a location and dispatch standpoint to take advantage of price volatility Exelon’s portfolio management approach in Texas utilized a mix of forward and spot sales based on its market views to capture value 2,000 0 2,600 2,500 2,400 2,300 2,200 2,100 Q3 2011 $107 2,403 Q3 2010 $49 ERCOT North Real Time On Peak Average ($/MWh) Exelon ERCOT Total Generation Exelon’s exceptional financial performance in Texas is a result of increased generation and our ability to capture value through the hedging program ERCOT Generation and On Peak Power Prices Q3 2011 vs. Q3 2010 (1) ERCOT Fossil Generation Capacity by Type (MW) (1) 1,998 +20% |
6 On Track for Merger Close in Early 2012 New York PSC FERC January 5, 2012 Statutory deadline Shareholder vote Shareholder vote November 17, 2011 Maryland PSC SEC NRC Texas PUC Secured approval from Texas PUC on August 3, 2011 DOJ Approvals Record Date October 7, 2011 Joint proxy statement declared effective October 11, 2011 Rebuttal testimony filed October 12, 2011 Evidentiary hearings begin October 31, 2011 FERC order expected by November 16, 2011 Filed merger approval application related filings on May 20, 2011. Settlement agreement filed with PJM Market Monitor on October 11, 2011 Filed for indirect transfer of Constellation Energy licenses on May 12, 2011 Submitted HSR filing on May 31, 2011 for review under U.S. antitrust laws and certified compliance with second request Q4 Q3 Q1 2012 2011 Regulatory proceedings are progressing as planned and we are on track to close in early 2012 Expect decision in Q4 2011 Note : On September 26 2011, the Department of Public Utilities in Massachusetts concluded that it does not have jurisdiction over the proposed transaction between Exelon and Constellation. th |
-400 -300 -200 -100 0 100 200 300 400 2015E 2014E 2013E 2012E 2011E 7 Antelope Valley Solar Ranch One (AVSR 1) (1) Based on alternating current (AC). Net Equity Cash Flows ($ millions) Equity Payback Cumulative Equity Cash Flows Annual Equity Cash Flows 230-MW (1) solar photovoltaic (PV) facility in Los Angeles County First portion of plant to come on line in October 2012; fully operational in 2013 25-year PPA with Pacific Gas & Electric ensures certainty in cash flows Summary Financials This investment diversifies ExGen’s portfolio by expanding to a new market, securing stable cash flows and increasing renewable energy under our control All-in cost of up to $1.36B; up to $646M of a non-recourse loan guaranteed by U.S. Department of Energy’s Loan Programs Office Exelon to invest up to $713M through 2013 – funded with cash and short-term debt Free cash flow accretive beginning in 2013; EBITDA run-rate of ~$75M per year once fully operational Expect to recover investment by 2015, largely driven by investment tax credits and other lax benefits |
EPA Regulations Will Move Forward Despite Delay Attempts 8 Proposed Rule issued in March 2011 • Rule provides regulatory certainty to industry • Stakeholder comments provided to EPA in August 2011 Final Rule expected in December 2011 Compliance starting in late 2014/early 2015 Final Rule issued in July 2011 • Rule provides template for future NOx and SO2 reductions Modest changes proposed in October 2011 • Some state emission budgets modified • Assurance provision moved to 2014 Compliance start remains January 2012 Impact in PJM ~10 GW Coal Retirements Announced to date ~15 GW EXC Estimate of Coal Retirements Cost of environmental upgrades and higher net ACRs influenced supplier bidding behavior in the PY 2014-2015 auction ~1,800 MW reduction in offered coal capacity vs. prior year auction ~7,000 MW reduction in cleared coal capacity vs. prior year auction (2) (1) Includes retirements announced by Duke, that will be part of PJM starting in 2012. (2) Expected coal retirements through 2015. (1) Air Toxics Rule Cross-State Air Pollution Rule PJM May 2011 RPM Auction PJM Retirements EPA and the industry are moving forward with implementation of forthcoming environmental regulations |
9 (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. Note: PPA = Power Purchase Agreement; T&D = Transmission and Distribution $2.10 $0.75 $2.47 $0.79 YTD 3Q 2011 2010 Outage Days (2) 3Q10 3Q11 Refueling 19 33 Non-refueling 19 3 Higher margins due to expiration of the PECO PPA: $0.27 Favorable market/portfolio conditions in the South: $0.10 Unfavorable capacity pricing: $(0.14) Higher O&M costs, including planned nuclear refueling outages: $(0.08) Higher income tax due to reduced manufacturing deduction as a result of T&D repairs: $(0.04) Higher nuclear fuel costs: $(0.02) Higher depreciation expense: $(0.02) Key Drivers – 3Q11 vs. 3Q10 (1) Exelon Generation Operating EPS Contribution |
10 Exelon Generation Hedging Program Exelon continued to make sales during Q3 to capture higher power prices driven by expanding heat rates and environmental rules $50.00 $49.00 $48.00 $47.00 $46.00 $45.00 $37.00 $36.00 $32.00 $34.00 $33.00 $35.00 $31.00 $30.00 9/18 8/28 8/7 7/17 6/26 6/5 5/15 4/24 4/1 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2013 2012 2011 NI Hub ATC 2013 NI Hub ATC 2012 West Hub ATC 2013 West Hub ATC 2012 Underlying Options Ratable 98% 86% 57% Physical Hedge % PJM West Hub & NI Hub ATC Prices |
11 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. 3Q10 Actual Actual Normal Heating Degree-Days 70 147 110 Cooling Degree-Days 854 785 624 3Q11 Increased storm costs: $(0.06) Electric distribution rates: $0.04 Key Drivers – 3Q11 vs. 3Q10 (1) YTD 3Q 2011 2010 $0.55 $0.18 $0.43 $0.17 |
12 (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; T&D = Transmission and Distribution $0.51 $0.19 $0.47 $0.16 YTD 3Q 2010 2011 3Q10 Actual Actual Normal Heating Degree-Days 0 18 36 Cooling Degree-Days 1,212 1,109 939 3Q11 2010 CTC collections, net of amortization expense: $(0.08) Increased storm costs: $(0.02) Electric and gas distribution rates: $0.03 Lower income tax due to T&D tax repairs deduction: $0.04 PECO Operating EPS Contribution Key Drivers – 3Q11 vs. 3Q10 (1) |
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 $375 million in Nuclear Uprates, $250 million for Exelon Wind spend and $200 million for Solar / Antelope Valley Solar Ranch One. (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) 800 725 3,450 4,850 CapEx (excluding Nuclear Fuel, Nuclear Uprates, Exelon Wind, Utility Growth CapEx and Solar CapEx) (750) (350) (850) (2,000) Nuclear Fuel n/a n/a (1,050) (1,050) Dividend (3) (1,400) Nuclear Uprates, Exelon Wind and Solar (4) n/a n/a (825) (825) 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 Federal Financing Bank Loan n/a n/a 125 125 Planned Debt Retirements (550) (250) -- (800) Other (7) -- (75) 150 275 Ending Cash Balance (1) $400 13 |
14 Investment strategy achieved positive 2011 YTD returns in a very challenging market environment due to effectiveness of asset allocations and hedging strategy : • Diversified asset allocation • Liability hedge • Pension plans are 83% funded as of September 30, 2011 • Anticipate no substantial changes to contribution plan S&P 500 Exelon Pension Fund Assets -8.7% 5.3% Pension Funds Performance 2011 YTD Returns at 9/30/2011 o Decreased equity investments and increased investment in fixed income securities and alternative investments o The liability hedge has offset more than 50% of the pension liability increase caused by lower interest rates Exelon’s pension investment strategy has effectively dampened the volatility of plan assets and plan funded status |
15 Exelon Generation Hedging Disclosures (as of September 30, 2011) |
16 Important Information The following slides are intended to provide additional information regarding the hedging program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon Generation’s gross margin (operating revenues less purchased power and fuel expense). The information on the following slides is not intended to represent earnings guidance or a forecast of future events. In fact, many of the factors that ultimately will determine Exelon Generation’s actual gross margin are based upon highly variable market factors outside of our control. The information on the following slides is as of September 30, 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. |
17 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 Portfolio Management Objective Align Hedging Activities with Financial Commitments % Hedged High End of Profit Low End of Profit Open Generation with LT Contracts Portfolio Optimization Portfolio Management Portfolio Management Over Time |
18 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 |
19 2011 2012 2013 Estimated Open Gross Margin ($ millions) (1)(2) $5,600 $5,150 $5,900 Reference Prices (1) Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (3) $4.11 $33.61 $45.07 $11.58 $4.24 $33.69 $45.46 $4.32 $4.80 $36.49 $48.45 $4.69 Exelon Generation Open Gross Margin and Reference Prices (1) Based on September 30, 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, $2.50 variable O&M. |
20 2011 2012 2013 Expected Generation (GWh) (1) 166,300 169,600 166,100 Midwest 98,500 98,300 96,100 Mid-Atlantic 56,500 56,800 56,100 South & West 11,300 14,500 13,900 Percentage of Expected Generation Hedged (2) 97-100% 85-88% 56-59% Midwest 97-100 85-88 56-59 Mid-Atlantic 96-99 88-91 57-60 South & West 94-97 68-71 49-52 Effective Realized Energy Price ($/MWh) (3) Midwest $43.00 $41.00 $40.00 Mid-Atlantic $56.50 $50.00 $50.50 South & West $6.00 $1.00 $0.00 Generation Profile (1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity. Expected generation is based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 12 refueling outages in 2011 and 10 refueling outages in 2012 and 2013 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.1%, 93.5% and 93.3% in 2011, 2012 and 2013 at Exelon-operated nuclear plants. These estimates of expected generation in 2012 and 2013 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Percent of expected generation hedged is the amount of equivalent sales divided by the expected generation. Includes all hedging products, such as wholesale and retail sales of power, options, and swaps. Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. (3) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. |
21 Gross Margin Sensitivities with Existing Hedges ($ 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) $5 $(5) $5 $(5) +/- $10 2012 $65 $(30) $70 $(50) $40 $(35) +/- $45 2013 $305 $(265) $210 $(205) $145 $(140) +/- $50 Exelon Generation Gross Margin Sensitivities (with Existing Hedges) (1) Based on September 30, 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. |
22 $5,700 $6,200 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 2011 2012 2013 $5,500 $6,900 Exelon Generation Gross Margin Upside / Risk (with Existing Hedges) 95% case 5% case $7,150 $7,050 (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 September 30, 2011. |
23 Midwest Mid-Atlantic South & West Step 1 Start with fleetwide open gross margin $5.60 billion Step 2 Determine the mark-to-market value of energy hedges 98,500GWh * 98% * ($43.00/MWh-$33.61MWh) = $0.91 billion 56,500GWh * 97% * ($56.50/MWh-$45.07MWh) = $0.63 billion 11,300GWh * 95% * ($6.00/MWh-$11.58MWh) = $(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: MTM value of energy hedges: Estimated hedged gross margin: $5.60 billion $0.91billion + $0.63billion + $(0.06) billion $7.08 billion Illustrative Example of Modeling Exelon Generation 2011 Gross Margin (with Existing Hedges) |
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 $4.07 2013 $4.62 Rolling 12 months, as of October 20 2011. Source: OTC quotes and electronic trading system. Quotes are daily. Forward NYMEX Coal 2012 $74.25 2013 $77.25 2012 Ni-Hub $39.86 2013 Ni-Hub $41.73 2013 PJM-West $53.74 2012 PJM-West $51.14 2012 Ni-Hub $26.79 2013 Ni-Hub $28.24 2013 PJM-West $40.19 2012 PJM-West $38.43 24 4.0 4.5 5.0 5.5 6.0 6.5 7.0 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 35 40 45 50 55 60 65 70 75 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 50 55 60 65 70 75 80 85 90 95 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 20 25 30 35 40 45 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 th |
4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 8.2 8.4 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 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 35 40 45 50 55 60 65 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 10/10 11/10 12/10 1/11 2/11 3/11 4/11 5/11 6/11 7/11 8/11 9/11 10/11 Market Price Snapshot 2013 10.64 2012 10.89 2012 $43.23 2013 $48.04 2012 $3.97 2013 $4.51 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 $12.07 2013 $12.96 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder 25 Rolling 12 months, as of October 20 2011. Source: OTC quotes and electronic trading system. Quotes are daily. th |
26 Appendix |
Maryland PSC Review Schedule (Case No. 9271) 27 Significant Events Date of Event Filing of Application May 25, 2011 Intervention Deadline June 24, 2011 Prehearing Conference June 28, 2011 Filing of Staff, Office of People Counsel and Intervenor Testimony September 16, 2011* Filing of Rebuttal Testimony October 12, 2011* Filing of Surrebuttal Testimony October 26, 2011 Status Conference October 28, 2011 Evidentiary Hearings October 31, 2011 - November 18, 2011 Public Comment Hearings November 29, December 1 & December 5, 2011 Filing of Initial Briefs December 1, 2011 Filing of Reply Briefs December 15, 2011 Decision Deadline January 5, 2012 * Initial intervenor testimony with respect to market power was due on September 23 for all parties except for the Independent Market Monitor and rebuttal testimony with respect to market power was due on October 17 . rd th |
ComEd Load Trends Weather-Normalized Load Year-over-Year 28 4Q11 3Q11 2Q11 1Q11 4Q10 3Q10 2Q10 1Q10 Gross Metro Product Residential Large C&I All Customer Classes Chicago U.S. Unemployment rate (1) 2011 annualized growth in gross domestic/metro product (2) Note: C&I = Commercial & Industrial Key Economic Indicators Weather-Normalized Load 2010 3Q11 2011E Average Customer Growth 0.2% 0.5% 0.5% Average Use-Per-Customer (1.4)% (2.9)% (1.7)% Total Residential (1.2)% (2.4)% (1.2)% Small C&I (0.6)% (2.2)% (0.8)% Large C&I 2.6% 0.1% 0.1% All Customer Classes 0.2% (1.4)% (0.6)% (1) Source: U.S. Dept. of Labor (September 2011) and Illinois Department of Employment Security (September 2011) (2) Source: Global Insight (August 2011) -6% -4% -2% 0% 2% 4% 6% 9.1% 1.6% 10.5% 1.0% |
29 PECO Load Trends Weather-Normalized Load Note: C&I = Commercial & Industrial 4Q11 3Q11 2Q11 1Q11 4Q10 3Q10 2Q10 1Q10 Gross Metro Product Residential Large C&I All Customer Classes Philadelphia U.S. Unemployment rate (1) 9.0% 9.1% 2011 annualized growth in gross domestic/metro product (2) 0.7% 1.6% 2010 3Q11 2011E Average Customer Growth 0.3% 0.3% 0.3% Average Use-Per-Customer 0.3% 1.8% 1.9% Total Residential 0.5% 2.1% 2.3% Small C&I (1.9)% (3.2)% (1.0)% Large C&I 0.8% (0.6)% (2.7)% All Customer Classes 0.1% (0.1)% (0.5)% (1) Source: U.S. Dept. of Labor data (September 2011) – US U.S. Dept. of Labor prelim. data (August 2011) – Philadelphia (2) Source: Global Insight (August 2011) Weather-Normalized Load Year-over-Year Key Economic Indicators -6% -4% -2% 0% 2% 4% 6% |
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) (122) (131) Available Capacity Under Facilities (2) 999 599 5,478 7,569 Outstanding Commercial Paper -- -- (28) (356) Available Capacity Less Outstanding Commercial Paper $999 $599 $5,450 $7,213 Available Capacity Under Bank Facilities as of October 21, 2011 Exelon bank facilities are largely untapped (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. 30 |
31 Key Credit Metrics (1) See slide 32 for reconciliations to GAAP. (2) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of October 14, 2011. (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. 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) Exelon PECO ComEd 2011E 2010A 2009A Exelon PECO ComEd 2011E 2010A 2009A Exelon PECO ComEd 2011E 2010A 2009A FFO/Debt (1) Interest Coverage (1) Debt to Cap (1) 40% 50% 60% 70% 80% 0X 2X 4X 6X 8X 10X 12X 10% 20% 30% 40% 50% ExGen/ Corp ExGen/ Corp ExGen/ Corp |
32 Exelon Consolidated Metric Calculations and Ratios (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 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 |
33 3Q GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended September 30, 2010 ExGen ComEd PECO Other Exelon 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.75 $0.18 $0.19 $(0.01) $1.11 2007 Illinois electric rate settlement 0.00 - - - 0.00 Mark-to-market impact of economic hedging activities 0.14 - - - 0.14 Unrealized gains related to nuclear decommissioning trust funds 0.09 - - - 0.09 Retirement of fossil generating units (0.02) - - - (0.02) Emission allowances impairment (0.05) - - - (0.05) 3Q 2010 GAAP Earnings (Loss) Per Share $0.91 $0. 18 $0.19 $(0.01) $1.27 Three Months Ended September 30, 2011 ExGen ComEd PECO Other Exelon 2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.79 $0.17 $0.16 $0.01 $1.12 Mark-to-market impact of economic hedging activities (0.08) - - - (0.08) Unrealized losses related to nuclear decommissioning trust funds (0.12) - - - (0.12) Asset retirement obligation (0.03) - 0.00 - (0.02) Retirement of fossil generating units (0.00) - - - (0.00) Constellation acquisition costs (0.00) (0.00) (0.00) (0.01) (0.02) AVSR 1 acquisition costs (0.01) - - - (0.01) Wolf Hollow acquisition 0.03 - - - 0.03 3Q 2011 GAAP Earnings (Loss) Per Share $0.58 $0.17 $0.16 $(0.00) $0.90 |
34 YTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Nine Months Ended September 30, 2010 ExGen ComEd PECO Other Exelon 2010 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $2.10 $0.55 $0.51 $(0.06) $3.10 2007 Illinois electric rate settlement (0.01) - - - (0.01) Mark-to-market impact of economic hedging activities 0.25 - - - 0.25 Unrealized gains related to nuclear decommissioning trust funds 0.04 - - - 0.04 Non-cash charge resulting from health care legislation (0.04) (0.02) (0.02) (0.02) (0.10) Non-cash remeasurement of income tax uncertainties 0.10 (0.16) (0.03) (0.01) (0.10) Retirement of fossil generating units (0.05) - - - (0.05) Emission allowances impairment (0.05) - - - (0.05) YTD 2010 GAAP Earnings (Loss) Per Share $2.34 $0.37 $0.46 $(0.09) $3.08 Nine Months Ended September 30, 2011 ExGen ComEd PECO Other Exelon 2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $2.47 $0.43 $0.47 $(0.03) $3.34 Mark-to-market impact of economic hedging activities (0.34) - - - (0.34) Unrealized losses related to nuclear decommissioning trust funds (0.07) - - - (0.07) Retirement of fossil generating units (0.04) - - - (0.04) Asset retirement obligation (0.03) - 0.00 - (0.02) Constellation acquisition costs (0.00) (0.00) (0.00) (0.03) (0.04) 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 YTD 2011 GAAP Earnings (Loss) Per Share $1.99 $0.44 $0.47 $(0.07) $2.84 |
35 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 • Changes in decommissioning obligation and asset retirement 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 • One-time benefits reflecting ComEd’s 2011 distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010 • Certain costs associated with Exelon’s acquisition of a wind portfolio (now known as Exelon Wind) and AVSR 1, and Exelon’s proposed merger with Constellation • Non-cash gain on purchase in connection with the acquisition of Wolf Hollow, net of acquisition costs • Non-cash charge remeasurement of income tax uncertainties • Non-cash charge resulting from passage of Federal health care legislation • Costs associated with the 2007 electric rate settlement agreement • Impairment of certain emission allowances • Other unusual items • Significant changes to GAAP Operating earnings guidance assumes normal weather for remainder of the year |