Earnings Conference Call • 1 st Quarter 2009 April 23, 2009 EXHIBIT 99.2 |
2 Forward-Looking Statements This presentation includes forward-looking statements. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements made herein. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed in (1) Exelon’s 2008 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 2009 Quarterly Report on Form 10-Q (to be filed on April 23, 2009) in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13 and (3) other factors discussed in Exelon’s filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this communication. Exelon does not undertake any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this communication, except as required by law. 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 attachments to the earnings release and the appendix to this presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings and non-GAAP cash flows to GAAP cash flows. |
3 3 Our Sustainable Advantage Remains |
4 Key Financial Messages Q1 operating results of $1.20/share driven by: Exceptional nuclear operations – 96.2% capacity factor Increased electric distribution revenues at ComEd and gas distribution revenues at PECO due to 2008 rate case decisions Benefit from Illinois tax ruling Reduced load in ComEd and PECO service territories Reaffirming 2009 operating earnings guidance of $4.00-$4.30/share 91-94% of 2009 expected generation hedged (1) On track to keep 2009 operating O&M (2) costs flat to 2008 at $4.5 billion Well-positioned in challenging economic times Strong cash flow from operations (3) – forecasted at $5.1 billion for 2009, an increase of $350 million over original planning assumptions Completed $250 million PECO bond issuance in Q1 2009 and limited debt maturities in 2009 ($29 million total) (4) Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (1) As of February 28, 2009. (2) Operating O&M excludes Decommissioning impact. ComEd and PECO operating O&M excludes energy efficiency spend recoverable under a rider. (3) Cash Flow from Operations primarily includes net cash flows provided by operating activities (excluding counterparty collateral activity) and net cash flows used in investing activities other than capital expenditures. (4) Excludes securitization debt and includes capital leases. |
5 $0.73 $0.91 $0.15 $0.17 $0.17 $0.07 2008 2009 Operating EPS $1.20 HoldCo/Other ExGen PECO ComEd 1st Quarter (Q1) $0.93 All Exelon operating companies reported higher quarter over quarter earnings Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. $0.88 $1.08 GAAP EPS |
6 Exelon Generation Operating EPS Contribution 2009 2008 Key Drivers – Q1 ’09 vs. Q1 ’08 (1) Higher nuclear volume due to fewer nuclear refueling outages: +$0.07 Favorable portfolio/market conditions: +$0.04 Higher nuclear fuel costs: ($0.01) Lower O&M costs due to fewer nuclear refueling outages, partially offset by higher inflation and pension & OPEB expense: +$0.03 Activity related to Nuclear Decommissioning Trust Funds: +$0.01 (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 Q1 2009 $0.73 $0.91 34 104 Refueling 13 26 Non-refueling Q1 2009 Q1 2008 Outage Days |
7 Key Drivers – Q1 ’09 vs. Q1 ’08 (1) Higher electric distribution rates: +$0.06 Benefit from Illinois tax ruling: +$0.05 Reduced load: ($0.01) Higher pension and OPEB expense largely offset by cost savings initiatives: ($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 Q1 2009 2009 2008 $0.07 $0.17 |
8 PECO Operating EPS Contribution Key Drivers – Q1 ’09 vs. Q1 ’08 (1) Higher gas distribution rates: +$0.03 Weather: +$0.02 Competitive Transition Charge (CTC) amortization: ($0.02) Higher O&M costs primarily due to bad debt expense: ($0.01) Reduced load: ($0.01) 2009 2008 (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 Q1 2009 $0.15 $0.17 |
9 ComEd Load Trends Weather-Normalized Load Customer Usage by Revenue Class Key Economic Indicators Top 380 Customer Usage by Segment Other 2% Residential 31% Small C&I 36% 380 Large C&I 18% Other Large C&I 13% 3% Leisure & Hospitality 9% Trade, Transportation & Utilities 11% Finance, Professional & Business Services 12% Health & Educational Services 13% Government 52% Manufacturing Chicago U.S. Unemployment rate (1) 9.1% 8.5% Q1 2009 annualized growth in gross domestic/metro product (2) (5.2%) (4.3%) 1/09 Home price index (3) (16.4%) (19%) (1) Source: Illinois Dept. of Employment Security and U.S. Dept. of Labor (April 2009 reports) (2) Source: Moody’s Economy.com (April 2009) (3) Source: S&P Case-Shiller Index (4) Adjusted for leap year impact (5) Not adjusted for leap year impact Q4 2008 Q1 2009 (4) Q1 2009 (5) 2009E (5) Customer Growth 0.1% (0.2%) (0.2%) 0.2% Average Use-Per-Customer (0.6%) (1.0%) (2.2%) (1.0%) Total Residential (0.5%) (1.2%) (2.4%) (0.8%) Small C&I (2.9%) (1.3%) (2.4%) (0.7%) Large C&I (1.0%) (5.3%) (6.4%) (2.6%) All Customer Classes (1.6%) (2.5%) (3.6%) (1.3%) Note: C&I = Commercial & Industrial |
10 PECO Load Trends Other 2% Other Large C&I 21% 150 Large C&I 21% Small C&I 22% Residential 34% Weather-Normalized Electric Load Q4 2008 Q1 2009 (3) Q1 2009 (4) 2009E (4) Customer Growth 0.5% 0.1% 0.1% 0.2% Average Use-Per-Customer (0.9%) 0.1% (1.1%) (0.2%) Total Residential (0.4%) 0.2% (1.0%) 0.0% Small C&I 0.7% 0.0% (1.2%) (0.8%) Large C&I (2.4%) (3.3%) (4.4%) (2.8%) All Customer Classes (1.1%) (1.1%) (2.2%) (1.2%) Customer Usage by Revenue Class Philadelphia U.S. Unemployment rate (1) 7.6% 8.5% Q1 2009 annualized growth in gross domestic/metro product (2) (4.8%) (4.3%) Key Economic Indicators Top 150 Customer Usage by Segment 18% Health & Educational Services 19% Manufacturing 21% Petroleum 3% Retail Trade 4% Other 9% Transportation, Communication & Utilities 13% Finance, Insurance & Real Estate 13% Pharmaceuticals (1) Source: Moody's Economy.com (March 2009) and U.S Dept. of Labor (April 2009) (2) Source: Moody’s Economy.com (April 2009) (3) Adjusted for leap year impact (4) Not adjusted for leap year impact |
11 Q1 07 Q1 08 Q1 09 ComEd and PECO Accounts Receivable >60 days 31-60 days 0-30 days ComEd Accounts Receivable (1) Through the first quarter of 2009 ComEd has experienced limited deterioration in its accounts receivable aging; PECO has experienced a slight improvement % of AR Q1 07 Q1 08 Q1 09 PECO Accounts Receivable (1) % of AR $785M $821M $723M $811M $846M $831M (1) Accounts receivable amounts include unbilled receivables and are gross of allowance for uncollectible accounts at ComEd and PECO and long-term receivables at PECO. >60 days 31-60 days 0-30 days |
12 2009 Operating Earnings Guidance 2009E 2008A $0.49 $3.46 $4.20 ComEd PECO Exelon Generation ComEd distribution revenue PECO gas revenue O&M and other Pension/OPEB Inflation Cost reduction initiatives Bad debt expense Nuclear fuel costs Depreciation and amortization PECO CTC 2009 Earnings Drivers ComEd PECO Exelon Generation Holdco Holdco Exelon $0.33 Exelon $4.00 - $4.30 (1) $0.45 - $0.55 $0.45 - $0.55 $3.10 - $3.35 (1) Adjusted (non-GAAP) Operating Earnings Guidance. Excludes the earnings impact of certain items as disclosed in the Appendix. Note: A = Actual; E = Estimate Reaffirming 2009 operating earnings guidance of $4.00-$4.30/share (1) - expect second quarter 2009 results between $0.95 to $1.05/share |
13 Well-Positioned in Near-Term Economic Uncertainty • Hedging strategy provides near-term cash flow stability and protects investment-grade balance sheet • 91-94% and 81-84% of expected generation hedged in 2009 and 2010, respectively (1) Risk management • Proven management team • Lowest-cost nuclear fleet operator with ~94% annual capacity factor Best-in-class management / operations • Nuclear remains a low-cost generation source • Improving utilities’ performance and regulatory environment Basics of business unchanged • Nation’s largest nuclear fleet ~140,000 GWhs of annual production Market leader • Progress made on transition to competitive markets in PA - PAPUC approved PECO's procurement settlement on April 16th; initial residential procurement will be held in June 2009 • ComEd on path to financial recovery • Positively levered to long-term fundamentals Long-term value in place • Strong and consistent cash flows from operations (2) – $5.1 billion estimated in 2009 • ~$6.9 billion of available credit facilities as of April 17, 2009 • Completed $250 million PECO bond issuance in Q1 2009 • Total debt maturities of $29 million (3) through the end of 2009 Sufficient liquidity Investment Criteria Exelon Profile (1) As of February 28, 2009. (2) Cash Flow from Operations primarily includes net cash flows provided by operating activities (excluding counterparty collateral activity) and net cash flows used in investing activities other than capital expenditures. (3) Excludes securitization debt and includes capital leases. |
14 Appendix |
15 Cost and Capital Management • Clearly define governance and oversight model • Optimize the Exelon operational structure to drive efficiency and accountability, reducing complexity and cost • Provide better visibility on cost drivers and productivity • Process improvement and focus on high-value work • Continue to manage capital spending Driving productivity and cost reduction while maintaining superior operations We remain committed to holding 2009 O&M flat to 2008, which includes realizing $150 million of sustainable cost savings this year $4,500 (2) $4,500 Exelon Consolidated (3) $700 $750 PECO $1,050 $1,100 ComEd $2,750 $2,700 Exelon Generation 2009E 2008A O&M Expense (1) (in millions) (1) Reflects operating O&M data and excludes Decommissioning impact. ComEd and PECO operating O&M exclude energy efficiency spend recoverable under a rider. (2) Reflects ~$175 million increase in operating O&M expense from 2008A to 2009E due to higher pension and OPEB expense. (3) Exelon Consolidated includes operating O&M expense and Capital Expenditures from Holding Company. $3,350 $3,200 Exelon Consolidated (3) $400 $400 PECO $875 $950 ComEd $2,000 $1,750 Exelon Generation 2009E 2008A CapEx (in millions) |
16 2009 Pension and OPEB Expense and Contributions Pension and OPEB Plans Key Metrics – 12/31/08 ($ in millions) Pension Assets $6,660 Obligations $10,840 2009E 2008 $85 $210 $160 $210 $80 $90 $163 $155 2009E 2008 (1) Excludes settlement charges. (2) Contributions reflect the application of recently issued U.S. Treasury Department guidance and cover both the qualified and non-qualified plans. Management has not yet made a final decision regarding its 2009 pension contributions and may make additional discretionary contributions based upon final interpretations of the Worker, Retiree and Employer Recovery Act of 2008. (3) Management has not yet made a decision regarding its 2009 OPEB contributions. Approximately $100 million of the estimated 2009 OPEB contributions is discretionary. Contributions shown above include contributions paid out of corporate assets. (4) Assumes a 20% overall capitalization rate for pension and OPEB costs. Note: OPEB = other postretirement benefits; EROA = expected return on assets (1) (2) (3) OPEB Assets $1,220 Obligations $3,340 Key Metrics 2008 asset return -26% 12/31/08 discount rate 6.09% Assumed long-term EROA 8.5% YTD asset returns through 3/31/09 -6% Pre-Tax Expense $0 $50 $100 $150 $200 $250 Pension OPEB (4) Cash Contributions $0 $50 $100 $150 $200 $250 Pension OPEB |
17 Illinois Power Agency Procurement Plan • On January 7, 2009, the Illinois Commerce Commission approved (1) , with minor modifications, the Illinois Power Agency’s (IPA) proposed procurement plan filed in September 2008 • In April/May the remaining ComEd 2009- 2010 load (~29% of the total) and a portion of its 2010-2011 load (~8% of the total) will be procured through a procurement event ComEd files retail generation rates By May 6 Procurement administrator submits confidential report By April 30 Bidders qualified to submit bids for procurement event April 23 Potential bidders submit qualifying proposals April 15 – 20 2009 IPA Procurement Event – Key Dates Bids due April 29 ICC decision on RFP results and public release of wholesale energy prices By May 4 NOTE: Chart is for illustrative purposes only. Assumes constant load profile each year. Jun 2007 Jun 2008 Jun 2009 Jun 2010 Jun 2011 Jun 2012 Jun 2013 Future Procurement by Illinois Power Agency Auction Contracts Financial Swap 3/08 RFP 4/09 RFP 2010 2010 2011 2012 2011 Estimated Volumes to Secure in 2009 IPA Procurement Event (GWh) Off-Peak Peak Contract Period 2,461 7,673 983 June 2010 – May 2011 5,712 June 2009 – May 2010 The procurement event will include monthly peak and off-peak standard wholesale block energy products (in 50 MW blocks) to be delivered to NiHub (1) Reference: ICC Docket#08-0519 4/09 RFP |
18 PECO Post-2010 Procurement Plan PAPUC approved PECO's procurement settlement on April 16 th ; initial residential procurement will be held in June 2009 Procurement plan for obtaining default service includes a portfolio of full requirements and spot products competitively procured through multiple RFP solicitations Mitigation plan includes early staggered procurement, voluntary post-rate cap phase-in, gradual phase-out of declining block rate design, customer education, enhanced retail choice program and low-income rate design changes Default Service Procurement and Mitigation Filing Early Phase-in Filing Procurement Settlement Early phase-in proposal provides an opt-in program for customers to pre-pay PAPUC approval in March 2009 allows for enrollment to begin as early as May 2009 80 3 Months Winter On-Peak (5 X 16) (Dec., Jan., Feb.) 130 3 Months Summer On-Peak (5 X 16) (June, July, Aug.) 160 100 50 12 months 24 months 60 months Baseload (24 X 7) MW Duration Residential Forward Energy Block Products 90% full requirements with 1-year (70%) and 2-year (20%) terms; 10% full requirements spot Small Commercial (peak demand <100 kW) Day-ahead hourly priced service; 1-year fixed price optional service from 1/1/11 to 12/31/11 Large Commercial & Industrial (peak demand >500 kW) 85% full requirements with 1-year term; 15% full requirements spot Medium Commercial (peak demand >100 but <=500 kW) 75% full requirements with 1-year (30%) and 2-year (45%) terms; 20% energy block and 5% spot Residential Products Customer Class |
19 2009 Projected Sources and Uses of Cash 5,100 2,900 950 1,250 Cash Flow from Operations (1) (50) 0 250 (50) Other (550) 0 (250) (50) Net Financing (excluding Dividend): (2) 250 0 250 0 Planned Debt Issuances (3)(4) Net Financing (excluding Dividend): (2) (750) 0 (750) 0 Planned Debt Retirements (5) $500 $400 $50 $50 Beginning Cash Balance (3,350) (2,000) (400) (875) Capital Expenditures $1,700 $1,300 $350 $375 Cash Available before Dividend (1,400) Dividend (6) $300 Cash Available after Dividend Exelon (7) ($ in Millions) (1) Cash Flow from Operations primarily includes net cash flows provided by operating activities (excluding counterparty collateral activity) and net cash flows used in investing activities other than capital expenditures. PECO Cash Flow from Operations includes $500M for Competitive Transition Charges. (2) Net Financing (excluding Dividend) = Net cash flows used in financing activities excluding dividends paid on common and preferred stock. (3) Excludes Exelon Generation and ComEd tax-exempt bonds that are backed by letters of credit (LOCs), which expire in 2009. Generation and ComEd are currently evaluating whether they will reissue this debt in the variable rate mode with a letter of credit in order to increase the value and marketability of the debt, or reissue the debt and change the interest rate mode of the bonds into a put mode or fixed rate to maturity, which does not require a letter of credit. (4) Excludes PECO’s Accounts Receivable Agreement with Bank of Tokyo. Assumes PECO’s A/R Agreement is extended in accordance with its terms beyond September 18, 2009. (5) Planned Debt Retirements are $17M, $728M, and $12M for ComEd, PECO, and ExGen, respectively. Includes securitized debt. (6) Assumes 2009 Dividend of $2.10 per share. Dividends are subject to declaration by the board of directors. (7) Includes cash flow activity from Holding Company, eliminations, and other corporate entities. |
20 Sufficient Liquidity (1) Excludes previous commitment from Lehman Brothers Bank. (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 cash flow activity from Holding Company, eliminations, and other corporate entities. (50) -- -- (50) Outstanding Facility Draws (288) (127) (15) (141) Outstanding Letters of Credit $7,317 $4,834 $574 $952 Aggregate Bank Commitments (1) 6,979 4,707 559 761 Available Capacity Under Facilities (2) (94) -- -- -- Outstanding Commercial Paper $6,885 $4,707 $559 $761 Available Capacity Less Outstanding Commercial Paper Exelon (3) ($ in Millions) Exelon has minimal commercial paper outstanding and its bank facilities are largely untapped Available Capacity Under Bank Facilities as of April 17, 2009 |
21 Projected 2009 Key Credit Measures BBB A- BBB+ BBB- S&P Credit Ratings (3) BBB+ A BBB BBB+ Fitch Credit Ratings (3) A3 A2 Baa2 Baa1 Moody’s Credit Ratings (3) 3.9x 4.0x FFO / Interest ComEd: 20% 15% FFO / Debt 42% 49% Rating Agency Debt Ratio 3.4x 3.2x FFO / Interest PECO: 15% 12% FFO / Debt 48% 53% Rating Agency Debt Ratio 23% 45% Rating Agency Debt Ratio 128% 51% FFO / Debt 30.3x 11.5x FFO / Interest Exelon Generation: 49% 36% 7.2x Without PPA & Pension / OPEB (2) 61% Rating Agency Debt Ratio 24% FFO / Debt 6.0x FFO / Interest Exelon Consolidated: With PPA & Pension / OPEB (1) Notes: Exelon and PECO metrics exclude securitization debt. See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to GAAP. (1) Reflects S&P updated guidelines, which include imputed debt and interest related to purchased power agreements (PPA), unfunded pension and other postretirement benefits (OPEB) obligations, capital adequacy for energy trading, operating lease obligations, and other off-balance sheet debt. Debt is imputed for estimated pension and OPEB obligations by operating company. (2) Excludes items listed in note (1) above. (3) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured ratings for ComEd and PECO as of April 17, 2009. On October 21, 2008, S&P put Exelon, ComEd, PECO and Exelon Generation on CreditWatch with negative implications. On October 21, 2008, Fitch placed Exelon and Exelon Generation on rating watch negative. On November 12, 2008, Moody’s placed the ratings of Exelon, Exelon Generation and PECO under review for possible downgrade. |
22 FFO Calculation and Ratios FFO Calculation = FFO - PECO Transition Bond Principal Paydown + Gain on Sale, Extraordinary Items and Other Non-Cash Items (3) + Change in Deferred Taxes + Depreciation, amortization (including nucl fuel amortization), AFUDC/Cap. Interest Add back non-cash items: Net Income Adjusted Interest FFO + Adjusted Interest = Adjusted Interest + 7% of Present Value (PV) of Operating Leases + Interest on imputed debt related to PV of Purchased Power Agreements (PPA), unfunded Pension and Other Postretirement Benefits (OPEB) obligations, and Capital Adequacy for Energy Trading (2) , as applicable - PECO Transition Bond Interest Expense Net Interest Expense (Before AFUDC & Cap. Interest) FFO Interest Coverage + Capital Adequacy for Energy Trading (2) FFO = Adjusted Debt + PV of Operating Leases + 100% of PV of Purchased Power Agreements (2) + Unfunded Pension and OPEB obligations (2) + A/R Financing Add off-balance sheet debt equivalents: - PECO Transition Bond Principal Balance + STD + LTD Debt: Adjusted Debt (1) FFO Debt Coverage Rating Agency Capitalization Rating Agency Debt Total Adjusted Capitalization Adjusted Book Debt = Total Rating Agency Capitalization + Off-balance sheet debt equivalents (2) Total Adjusted Capitalization = Rating Agency Debt + Off-balance sheet debt equivalents (2) Adjusted Book Debt = Total Adjusted Capitalization + Adjusted Book Debt + Preferred Securities of Subsidiaries + Total Shareholders' Equity Capitalization: = Adjusted Book Debt - Transition Bond Principal Balance + STD + LTD Debt: Debt to Total Cap Note: Reflects S&P guidelines and company forecast. FFO and Debt related to non-recourse debt are excluded from the calculations. (1) Uses current year-end adjusted debt balance. (2) Includes debt equivalents for A/R Financings, operating lease obligations, imputed debt related to PV of PPAs, underfunded Pension and OPEB obligations, and Capital Adequacy for Energy Trading. (3) Reflects depreciation adjustment for PPAs and decommissioning interest income and contributions. |
23 Q1 GAAP EPS Reconciliation 0.08 0.02 - - 0.06 Mark-to-market adjustments from economic hedging activities (0.06) - - - (0.06) Unrealized gains & losses related to nuclear decommissioning trust funds $0.88 $0.00 $0.15 $0.07 $0.66 Q1 2008 GAAP Earnings Per Share $0.93 $(0.02) $0.15 $0.07 $0.73 2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share (0.07) - - - (0.07) 2007 Illinois electric rate settlement Exelon Other PECO ComEd ExGen Three Months Ended March 31, 2008 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. (0.05) - - - (0.05) Unrealized gains & losses related to nuclear decommissioning trust funds (0.01) (0.01) - - - NRG acquisition costs (0.03) - - - (0.03) 2007 Illinois electric rate settlement 0.17 - - - 0.17 Mark-to-market adjustments from economic hedging activities (0.20) - - - (0.20) Impairment of certain generating assets $1.08 $(0.06) $0.17 $0.17 $0.80 Q1 2009 GAAP Earnings (Loss) Per Share $1.20 $(0.05) $0.17 $0.17 $0.91 2009 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share Exelon Other PECO ComEd ExGen Three Months Ended March 31, 2009 |
24 2009 Earnings Outlook • Exelon’s 2009 adjusted (non-GAAP) operating earnings outlook excludes the earnings impacts of the following: • Mark-to-market adjustments from economic hedging activities • Unrealized gains and losses from nuclear decommissioning trust fund investments primarily related to the Clinton, Oyster Creek, and Three Mile Island nuclear plants (the former AmerGen Energy Company, LLC units) • Any significant impairments of assets, including goodwill • Any changes in decommissioning obligation estimates • Costs associated with the 2007 Illinois electric rate settlement agreement, including ComEd’s previously announced customer rate relief programs • Costs associated with ComEd’s 2007 settlement with the City of Chicago • Certain costs associated with the proposed offer to acquire NRG Energy, Inc. • Other unusual items • Significant future changes to GAAP • Operating earnings guidance assumes normal weather for the remainder of the year |
25 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 February 28, 2009. The following slides were originally filed via Form 8-K on April 14, 2009. Going forward, we plan to update the 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. |
26 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 By design, our hedging program allows us to weather short-term, adverse market conditions while positioning us to participate in long-term upside potential % Hedged High End of Profit Low End of Profit Open Generation with LT Contracts Portfolio Optimization Portfolio Management Portfolio Management Over Time |
27 27 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 |
28 28 Open gross margin assumes all expected generation is sold at the Reference Prices listed below 2009 2010 2011 Estimated Open Gross Margin (millions) (1,2) $5,450 $5,900 $6,350 Reference Prices (1) Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (3) $4.71 $30.63 $45.08 ($1.08) $6.08 $31.64 $50.35 ($0.99) $6.69 $36.93 $54.18 $0.36 (1) Based on February 28, 2009 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 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. Exelon Generation Open Gross Margin and Reference Prices |
29 29 (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 2009 and 2010 and 11 refueling outages in 2011 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.3%, 92.7% and 92.8% in 2009, 2010 and 2011 at Exelon-operated nuclear plants. These estimates of expected generation in 2010 and 2011 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. (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. 2009 2010 2011 Expected Generation (GWh) (1) 170,500 166,100 167,500 Midwest 99,400 96,900 98,500 Mid-Atlantic 57,500 58,500 58,100 South 13,600 10,700 10,900 Percentage of Expected Generation Hedged (2) 91-94% 81-84% 40-43% Midwest 93-96 79-82 49-52 Mid-Atlantic 93-96 91-94 27-30 South 67-70 39-42 14-17 Effective Realized Energy Price ($/MWh) (3) Midwest $48.00 $48.00 $47.25 Mid-Atlantic $37.00 $37.50 $71.25 ERCOT North ATC Spark Spread $3.75 $5.00 $7.00 Generation Profile |
30 30 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% 2009 $18 ($4) $10 ($9) $20 ($18) +/-$40 2010 $70 ($50) $115 ($115) $30 ($30) +/-$50 2011 $420 ($390) $265 ($265) $230 ($230) +/-$50 Exelon Generation Gross Margin Sensitivities (with Existing Hedges) (1) Based on February 28, 2009 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. |
31 31 95% case 5% case $6,800 $6,500 $5,800 $6,900 $6,100 $8,900 Exelon Generation Gross Margin Upside / Risk (with Existing Hedges) $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 2009 2010 2011 (1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels. 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 2010 and 2011 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 February 28, 2009. |
32 32 Midwest Mid-Atlantic ERCOT Step 1 Start with fleetwide open gross margin $5.45 billion Step 2 Determine the mark-to-market value of energy hedges 99,400GWh * 94% * ($48.00/MWh-$30.63/MWh) = $1.6 billion 57,500GWh * 94% * ($37.00/MWh-$45.08/MWh) = ($0.4 billion) 13,600GWh * 68% * ($3.75/MWh-($1.08)/MWh) = $0.0 billion Step 3 Estimate hedged gross margin by adding open gross margin to mark-to- market value of energy hedges Open gross margin: $5.45 billion MTM value of energy hedges: $1.6 billion + ($0.4 billion) + $0.0 billion Estimated hedged gross margin: $6.65 billion Illustrative Example of Modeling Exelon Generation 2009 Gross Margin (with Existing Hedges) |
33 50 60 70 80 90 100 110 120 130 140 150 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 20 30 40 50 60 70 80 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 35 45 55 65 75 85 95 105 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5.5 6.5 7.5 8.5 9.5 10.5 11.5 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 33 Market Price Snapshot Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West and Ni-Hub Wrap Forward Prices 2010 2011 Rolling 12 months, as of April 17, 2009. Source: OTC quotes and electronic trading system. Quotes are daily. Forward NYMEX Coal $6.07 $6.88 2010 2011 $58.56 $65.00 2010 Ni-Hub 2011 Ni-Hub 2011 PJM-West 2010 PJM-West 2010 Ni-Hub 2011 Ni-Hub 2011 PJM-West 2010 PJM-West $59.04 $65.20 $41.66 $23.22 $47.21 $24.11 $40.50 $43.03 |
34 6 7 8 9 10 11 12 13 14 15 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 8 8.2 8.4 8.6 8.8 9 9.2 9.4 9.6 9.8 10 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 45 50 55 60 65 70 75 80 85 90 95 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5 6 7 8 9 10 11 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 3/09 4/09 34 Market Price Snapshot 2011 2010 2010 2011 2010 2011 Houston Ship Channel Natural Gas Forward Prices ERCOT North On-Peak Forward Prices ERCOT North On-Peak v. Houston Ship Channel Implied Heat Rate 2010 2011 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder $5.75 $6.58 $59.74 $51.31 $8.92 $9.08 $7.32 $9.77 Rolling 12 months, as of April 17, 2009. Source: OTC quotes and electronic trading system. Quotes are daily. |