UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
November 2, 2009
Date of Report (Date of earliest event reported)
| Commission File |
Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS Employer Identification Number | ||
| 1-16169 | EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
23-2990190 | ||
| 333-85496 | EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 |
23-3064219 | ||
| 1-1839 | COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 |
36-0938600 | ||
| 000-16844 | PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
23-0970240 |
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Section 7 — Regulation FD
| Item 7.01. | Regulation FD Disclosure. |
On November 2-3, 2009, Exelon Corporation (Exelon) will participate in the Edison Electric Institute Financial Conference. During this conference, Exelon will present its 2010 adjusted (non-GAAP) operating earnings guidance of $3.60 to $4.00 per share. Attached as Exhibit 99.1 to this Current Report on Form 8-K are the presentation slides and handouts to be used at the conference.
Section 9 – Financial Statements and Exhibits
| Item 9.01. | Financial Statements and Exhibits. |
| (d) | Exhibits. |
| Exhibit No. |
Description |
|||||
| 99.1 | Presentation slides and handouts | |||||
* * * * *
This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 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 Third Quarter 2009 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 14; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| EXELON CORPORATION EXELON GENERATION COMPANY, LLC |
| /s/ MATTHEW F. HILZINGER |
| Matthew F. Hilzinger |
| Senior Vice President and Chief Financial Officer |
| Exelon Corporation |
| COMMONWEALTH EDISON COMPANY |
| /s/ JOSEPH R. TRPIK, JR. |
| Joseph R. Trpik, Jr. |
| Senior Vice President, Chief Financial Officer and Treasurer |
| Commonwealth Edison Company |
| PECO ENERGY COMPANY |
| /s/ PHILLIP S. BARNETT |
| Phillip S. Barnett |
| Senior Vice President and Chief Financial Officer |
| PECO Energy Company |
November 2, 2009
EXHIBIT INDEX
| Exhibit No. |
Description |
|||||
| 99.1 | Presentation slides and handouts |
 John
W. Rowe, Chairman and CEO Edison Electric Institute Financial
Conference November 2-3, 2009 Positioned for Sustained Value Exhibit 99.1 |
 2 Forward-Looking Statements This presentation includes forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995, that are subject to risks
and uncertainties. The factors that could cause actual results to differ
materially from these forward-looking statements include those discussed
herein as well as those discussed in (1) Exelon’s 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
Third Quarter 2009 Quarterly Report on Form 10-Q in (a) Part II, Other
Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information,
ITEM 1. Financial Statements: Note 14 and (3) other factors discussed in
filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). Readers are cautioned not to place undue
reliance on these forward-looking statements, which apply only as of the date
of this presentation. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after
the date of this presentation. This presentation includes references to adjusted (non-GAAP) operating earnings and
non-GAAP cash flows that exclude the impact of certain factors. We
believe that these adjusted operating earnings and cash flows are representative of the underlying operational results of the Companies. Please refer to the appendix to this presentation
for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP
earnings and non- GAAP cash flows to GAAP cash flows.
|
 3 Protect Today’s Value • Deliver superior operating performance • Advance competitive markets • Exercise financial discipline and maintain financial flexibility • Build healthy, self-sustaining delivery companies Grow Long-Term Value • Drive the organization to the next level of performance • Adapt and advance Exelon 2020 • Rigorously evaluate and pursue new growth opportunities in clean technologies and transmission • Build the premier, enduring competitive generation company + Exelon’s Strategic Direction Exelon remains focused on preserving and creating shareholder value |
 4 75% 80% 85% 90% 95% Range 5 Year Average Delivering High-Performing Operating Results • CAIDI: (1) 1 st quartile performance – YTD performance is the best on record • SAIFI: (1) 1 st quartile performance – YTD performance is the best on record • Targeting earned ROEs of ~8% in 2009, 9-10% in 2010 Nuclear Capacity Factor Exelon Power Fleet Availability 93.8% 90.7% 93.5% 91.2% 89.1% 94.1% 92.9% 93.8% 94.8% 95.8% 96.8% 80% 85% 90% 95% 100% 2005 2006 2007 2008 2009 YTD through 9/30 Fossil Fleet Commercial Availability Hydro Equivalent Availability • CAIDI: (1) 1 st quartile performance • SAIFI: (1) 1 st quartile performance – Improving trend since 2002 • Targeting earned ROEs > 11% in 2009- 2010, 9-11% starting in 2011, post transition to market-based electric prices 94.9% - EXC YTD through September 30, 2009 Operator (# of reactors as of 2008) (1) CAIDI (Customer Average Interruption Duration Index) and SAIFI (System Average
Interruption Frequency Index) quartile data is as of 2008, using IEEE 2.5 Beta method. |
 5 2008A 2009E 2010 (Original Est) 2010 (Revised Est) Announcing 2010 Guidance… And Maintaining Financial Commitments Streamlined O&M Expenses (1) (1) Reflects operating O&M data and excludes Decommissioning effect. ComEd and
PECO operating O&M exclude energy efficiency spend recoverable under a
rider. (1) Operating Earnings Guidance. Excludes the earnings
effect of certain items as disclosed in the Appendix. 2010 Operating EPS Guidance (1) • Generating 2010 cash flow from operations of $4.5 billion • Maintaining annual dividend of $2.10/share $2.55 - $2.80 $3.60 - $4.00 ComEd PECO Exelon Generation Holdco Exelon $0.60 - $0.70 $0.40 - $0.50 $4.4B $4.5B $4.35B $4.7B 0% 20% 40% 60% 80% 100% 2010 2011 2012 Exelon Midwest Mid-Atlantic South Executing on 36-month Ratable Hedging Program |
 6 $440 $280 $155 2009E 2010E 2011E Enhancing Financial Flexibility Lowered Cost of Debt Increased Future Cash Flexibility • $350 million contribution reduced estimated 2011 required contribution by over $1 billion • Reduced present value of contributions over 10 years by $300 million • Elected smoothing, which lowers volatility of future contributions • Executed $1.5 billion tender/make whole and refinancing • Expect ~$12 million in annual interest savings • Extends average maturity by 6.6 yrs $ millions Note: Chart reflects peers issuing Holding company and Generation company
debt. Estimated Pension Contributions ETR AYE PEG FPL EXC Prior PPL EXC Current 4% 5% 6% 7% 8% 0.0 2.0 6.0 8.0 10.0 12.0 14.0 Average Tenor (Yrs) 4.0 16.0 CEG EIX FE |
 7 • Focus: leverage our core competencies • Vision: pursue long-term value, analyzing opportunities across multiple scenarios • Discipline: invest only in projects / opportunities that create long-term value Exelon’s asset base, scope and operating excellence uniquely position us to pursue
value-enhancing opportunities Creating Consistent Value for Shareholders Exelon’s Value Creation Philosophy… ...Has Consistently Yielded Returns in Excess of Our Peers Three-year Average of ROIC less WACC Source: Company filings, Wall Street research and Exelon estimates. Peer group
includes AYE, CEG, EIX, ETR, FE, FPL, PPL and PSEG. 6% 3% EXC Peer Group |
 8 Nuclear Uprates - 1,300–1,500 MW of new Exelon nuclear capacity by 2017, the equivalent of a new nuclear plant at roughly half the cost of a new plant and no incremental operating costs - Approximately $725 million in investments to build smart grid infrastructure over the coming years with a regulated return on investment - Lowest carbon intensity in the sector, greatest upside when legislation enacted and enhancing industry-leading position with Exelon 2020 - Positioned to benefit from our fundamental view of recovery in natural gas and coal prices, heat rates, and demand growth - Leveraging transmission expertise to create Exelon Transmission Company with the goal of improving reliability, reducing congestion and moving renewable energy to population centers Deploying Capital for Shareholder Value Smart Grid Carbon Price Recovery Transmission |
 9 Positioning for Market Recovery • Wind: Only 3 GW of wind will come on line by 2012, less than $1/MWh price impact • Transmission: Constraints in the Midwest will be reduced Our View • Employing flexibility within our hedging program • Evaluating needed upgrades of the existing system to reduce constraints and improve power flow • Pursuing bilateral contracts, such as the recently announced 10- year contract with ODEC • NiHub forward ATC is 16% below historical spot prices which is inconsistent with movements in key price drivers: (1) – Chicago gas ($/MMBtu) +2% – PRB coal ($/ton)
+6% – ComEd
load +0.8% Positioned to Benefit Current Midwest Price Curve Midwest power markets have upside…2012 gross margin increases by ~$300 million for each $5/MWh increase in NiHub ATC (1) Reflects premium/(discount) of 2007-2009 average as compared to 2010-2012
average forward prices as of September 30, 2009. Reflects ComEd’s load growth estimate in 2010. 30 35 40 45 50 55 2010 2011 2012 2013 2014 9/30/09 Forward Prices NiHub ATC Prices Current opportunity Carbon opportunity assuming a $15/tonne price and Waxman- Markey allocations |
 10 Meeting Industry-Best Exelon 2020 Climate Commitments Note: Emissions abatement estimates for new generation capacity represents emissions
reduced in the market as a result of the project less emissions introduced due to the project (if any). Executable 2020 plan further enhances industry-leading position in a carbon constrained world Reduce or offset Exelon’s GHG emissions Help our customers reduce their GHG emissions Offer more low-carbon electricity in the marketplace Potential options to reach 2020 goal Approx. Total: 7.0-7.5 Additional Internal GHG Reductions Customer Energy Efficiency Programs PECO Alternative Energy Credits MW Recovery & Component Upgrades and Measurement Uncertainty Recapture Uprates Renewables 15.7 9.7 6.0 2.3 0.6 1.6 1.5 0.5 4.8 1.0-2.0 1.0 3.5 0.2 -2.5 0.0 2.5 5.0 7.5 10.0 12.5 15.0 17.5 2001 Carbon Footprint Reductions Achieved through 2008 Remaining Target Economic Projects Under All Price Scenarios Extended Power Uprates Wind New Natural Gas Plants Retire Coal Plants Offsets |
 11 11 Leading Advocate for Carbon Legislation |
 12 2010 Financial Outlook and Operating Data |
 13 The Exelon Companies ’08 Earnings: $2,293M ’08 EPS: $3.46 Total Debt: (1) $3.1B Credit Rating: (2) BBB Nuclear, Fossil, Hydro & Renewable Generation Power Marketing ‘08 Operating Earnings: $2.8B ‘08 EPS: $4.20 Assets: (1) $49.5B Total Debt: (1) $13.0B Credit Rating: (2) BBB- Note: All ’08 income numbers represent adjusted (Non-GAAP) Operating Earnings
and EPS. Refer to Appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. (1) As of September 30, 2009. (2) Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and
senior secured debt ratings for ComEd and PECO as of October 23, 2009. Pennsylvania Utility Illinois Utility ’08 Earnings: $219M $325M ’08 EPS: $0.33 $0.49 Total Debt: (1) $5.1B $3.0B Credit Ratings: (2) A- A- |
 14 Multi-Regional, Diverse Company Note: Owned megawatts based on Generation’s ownership, using annual mean ratings for nuclear units (excluding Salem) and summer ratings for Salem and the fossil and hydro units. As of September 30, 2009. Midwest Capacity Owned: 11,388 MW Contracted: 3,230 MW Total: 14,618 MW ERCOT/South Capacity Owned: 2,222 MW Contracted: 2,917 MW Total: 5,139 MW New England Capacity Owned: 182 MW Total Capacity Owned: 24,809 MW Contracted: 6,483 MW Total: 31,292 MW Electricity Customers: 1.6M Gas Customers: 0.5M Electricity Customers: 3.8M Generating
Plants Nuclear Hydro Coal/Oil/Gas Base-load Intermediate Peaker Mid-Atlantic Capacity Owned: 11,017 MW Contracted: 336 MW Total: 11,353 MW |
   15 2010 Operating Earnings Guidance 2010E 2009E $0.45 - $0.50 $3.10 - $3.15 $4.00 - $4.10 (1) ComEd PECO Exelon Generation 2010 Earnings Drivers ComEd PECO Exelon Generation Holdco Holdco Exelon $0.50 - $0.55 Exelon $3.60 - $4.00 (1) $0.60 - $0.70 $0.40 - $0.50 $2.55 - $2.80 NOTE: See “Key Assumptions” slide in Appendix. (1) Operating Earnings Guidance. Excludes the earnings effect of certain
items as disclosed in the Appendix. Issuing 2010 operating earnings guidance
of $3.60 – $4.00/share (1) ComEd RNF PECO RNF Generation RNF O&M Cost Savings Initiative Inflation Pension/OPEB Depreciation and amortization |
 16 Delivering on Cost Savings Commitments • Exelon is committed to $350 million of savings in 2010 from original planning assumptions – Half of the total O&M savings in 2010, or $175 million, will be sustainable
– Reduced positions by 500 (400 in corporate support and 100 at ComEd) – Freezing executive salaries and reducing other compensation benefits in 2010 – 2010 estimated O&M spend of $4.35 billion reflects $235 million and $190 million of pre-tax pension and OPEB expense, respectively (3) Exelon is driving productivity and cost reductions while maintaining superior
operations (1) Reflects operating O&M data and excludes
decommissioning effect. ComEd and PECO operating O&M exclude energy efficiency costs recoverable under a rider. (2) Exelon Consolidated includes operating O&M expense from Holding
Company. (3) See slides 25 and 26 for additional information regarding
potential variability of 2010 pension and OPEB expense. (4) 2010-2014 O&M is expected to grow at a compound annual growth rate of ~3% for ComEd, ~4% for PECO and ~5% for Exelon Generation. Note: Data contained on this slide is rounded. O&M Expense (1) 2008A 2009E 2010 (Original Plan) 2010 (Est.) $4.4B (2) $4.5B (2) $4.35B (2)(3) $4.7B (2) $2,700 Exelon Generation $700 PECO $1,000 ComEd 2010 O&M ($millions) (4) |
 17 Capital Expenditures Expectations 1,975 2,000 1,825 1,950 1,950 775 925 850 1,125 1,150 200 50 375 550 675 50 25 100 150 75 300 300 275 225 200 $0 $750 $1,500 $2,250 $3,000 $3,750 $4,500 2008A 2009E 2010E 2011E 2012E Base CapEx Nuclear Fuel Nuclear Uprates and Solar Smart Grid New Business at Utilities Exelon $3,125 $3,375 $3,375 $4,050 $4,150 2008A 2009E 2010E 2011E 2012E Exelon Generation Base CapEx 875 925 750 900 900 Nuclear Fuel 775 925 850 1,125 1,150 Nuclear Uprates 50 150 350 550 675 Solar - 50 25 - - Total ExGen 1,700 2,050 1,975 2,575 2,725 ComEd Base CapEx 675 675 625 625 625 Smart Grid/Meter 25 50 50 25 25 New Business 250 150 175 200 225 Total ComEd 950 875 850 850 875 PECO Base CapEx 350 350 400 400 400 Smart Grid/Meter - - 50 125 50 New Business 50 50 50 75 75 Total PECO 400 400 500 600 525 Corporate 75 50 50 25 25 Note: Data contained on this slide is rounded. $ millions |
 18 2010 Projected Sources and Uses of Cash (325) n/a (100) (225) Utility Growth CapEx (4) ($ millions) Exelon (8) Beginning Cash Balance (1) $725 Cash Flow from Operations (1)(2) 1,075 950 2,450 4,475 CapEx (excluding Nuclear Fuel, Nuclear Uprates and Solar Project, Utility Growth CapEx) (625) (400) (750) (1,825) Nuclear Fuel n/a n/a (850) (850) Dividend (3) (1,400) Nuclear Uprates and Solar Project n/a n/a (375) (375) Net Financing (excluding Dividend): Planned Debt Issuances (5,6) 250 0 300 550 Planned Debt Retirements (225) (400) 0 (1,025) Other (7) 25 175 0 125 Ending Cash Balance (1) $75 (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. Cash Flow from Operations for PECO and Exelon includes $572 million for competitive transition
charges. (3) Assumes 2010 dividend of $2.10 per share. Dividends are subject to declaration by the Board of Directors. (4) Represents new business and smart grid/smart meter investment. (5) Excludes Exelon Generation’s $213 million and ComEd’s $191 million
tax-exempt bonds that are backed by letters of credit (LOCs). Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. Assumes PECO’s A/R Agreement is extended
in accordance with its terms beyond September 16, 2010. (6) Exelon Generation’s $300 million financing includes a $50 million DOE loan for the City Solar Project and $250 million of debt to refinance a portion of Exelon Corp’s $400 million maturity. (7) “Other” includes PECO Parent Receivable, proceeds from options and expected changes in
short-term debt. (8) Includes cash flow activity from Holding Company, eliminations, and other corporate
entities. |
 19 Committed to Investment Grade Ratings Exelon believes that solid investment grade ratings are critical for managing and operating both regulated utilities and a commodity-based generation company Our investment grade rating increases the pool of lenders, provides access to a
broad range of trading counterparties, and enhances our strategic options
Commercial Business Opportunities • Ability to participate in or to bid competitively for PPAs and long- term transactions • Increased liquidity for energy trading: counterparties’ costs would increase for non-investment grade transactions, thereby reducing market participation Manageable Liquidity Requirements • Lower collateral requirements for energy trading • Ability to secure sizeable and sufficient bank credit facilities (currently $7.3B) • Use of guarantees (versus letters of credit) to fulfill NRC requirements for shortfalls in Nuclear Decommissioning Trust obligations Business and Financial Flexibility • Reliable access to long-term debt markets to meet sizeable capital needs • Lower cost and ability to extend maturity profile of debt (Generation’s recent $1.5B debt offering) • Access to commercial paper market Efficient Capital Markets Access • Avoid prepayments on long-term contracts (such as uranium), which reduce working capital requirements • Avoid restrictive bond covenants and secured financing transactions • Limits regulatory friction |
 20 Credit Ratings and Metrics 0% 10% 20% 30% 40% 50% 2007 2008 2009E 2010E Exelon ExGen/Corp ComEd PECO FFO / Debt (2) 2 4 6 8 10 2007 2008 2009E 2010E Exelon ExGen/Corp ComEd PECO FFO / Interest (2) (1) Current senior unsecured ratings for Exelon Corp and Generation and senior secured
ratings for ComEd and PECO as of October 23, 2009. (2) FFO/Debt metrics include the following standard adjustments: 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. (3) Indicated ratings are for Generation, whereas the FFO/Debt Target Range reflects
Generation FFO/Debt in addition to the debt obligations of Exelon Corp. Strong credit metrics for each company Evaluate the credit of each company on a stand-alone basis Company Moody's (1) S&P (1) Fitch (1) FFO/Debt Target Range (2) Exelon Corp Baa1 BBB- BBB+ ExGen/Corp (3) A3 BBB BBB+ 30-35% ComEd Baa1 A- BBB 15-18% PECO A2 A- A 15-18% |
 21 21 21 Credit Facility Plans • Exelon’s primary sources of short-term liquidity include credit facilities,
commercial paper, the money pool (excluding ComEd) and cash on hand
• Current total credit facility size is $7.3 billion, the largest in the power
sector • Large and diverse bank group – 23 banks committed to the facilities with each bank having less than 10% of the aggregate commitments • Recently closed on a $67 million 364-day credit facility with a group of 26
community and minority-owned banks Currently do not foresee increased liquidity needs post-2010 from PECO PPA
roll-off Exelon Corp + Exelon Generation – $5.8 billion facilities largely expire October 26, 2012 - plan to extend/refinance the facilities in 2010-2011 and currently do not foresee increased liquidity needs post-2010 from
PECO PPA roll-off (1) – Continued use of non-margining transactions and currently evaluating alternatives to
reduce reliance on bank credit ComEd – $952 million facility expires on February 16, 2011 – Plan to extend/refinance the facility in 2010 PECO – $574 million facility largely expires on October 26, 2012 – Plan to extend/refinance the facility in 2010-2011 (1) Assumes that the Exelon Corp credit facility will be used for Generation’s
liquidity needs and the continued use of non-margin transactions. |
 22 Sufficient Liquidity (1) Excludes previous commitment from Lehman Brothers Bank and commitments from
Exelon’s Community and Minority Bank Credit Facility. (2)
Available Capacity Under Facilities represents the unused bank commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. The amount of commercial paper outstanding does not reduce the available
capacity under the credit agreements. (3) Includes other corporate
entities. (35) -- -- (35) Outstanding Facility Draws (409) (154) (10) (241) Outstanding Letters of Credit $7,317 $4,834 $574 $952 Aggregate Bank Commitments (1) 6,873 4,680 564 676 Available Capacity Under Facilities (2) -- -- -- -- Outstanding Commercial Paper $6,873 $4,680 $564 $676 Available Capacity Less Outstanding Commercial Paper Exelon (3) ($ millions) Exelon has no commercial paper outstanding and its bank facilities are largely
untapped Available Capacity Under Bank Facilities as of October 15, 2009
|
 23 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 Exelon Corp Exelon Generation ComEd PECO Debt Maturity Profile Note: Balances shown exclude securitized debt and includes capital leases. Recent refinancing of Exelon Generation and Exelon 2011 maturities decreased average
cost of debt, extended average maturities, and reduced refinancing
risk |
 24 Discretionary Pension Contribution Investing in pension plan with $350 million cash on hand is estimated to create $1 billion of financial flexibility in 2011 • Took advantage of federal relief provided by the Worker, Retiree and Employer Recovery Act of 2008 by making smoothing election and contribution in September to impact 2008 plan year • Made $350 million discretionary pension contribution with smoothing election (1) for the 2008 Plan Year. – $1 billion reduction in forecasted contribution in 2011 – Smoothing election reduces present value of estimated future contributions by ~$300M
over the next 10 years compared to status quo – Lowers volatility in future contributions, as smoothing election uses 24-month average of asset returns • Evaluated within our Value Return Framework: – Funded with $350 million of cash on hand generated in excess of original 2009
plan – Increases future financial flexibility with excess cash “today” (1) Contributions reflect the impact of electing the option to smooth asset returns provided under the Worker,
Retiree and Employer Recovery Act of 2008, which allows the use of average assets, including
expected returns (subject to certain limitations) for a 24-month period prior to the measurement date, in the determination of funding requirements. |
 25 Potential Variability in Future Pension Expense and Contributions $155 $3,845 $295 $280 $3,925 $285 6.09% for 2009 5.45% for 2010 5.63% for 2011 20.05% in 2009 8.50% in 2010 8.50% in 2011 B – Forecast as of September 30 Unfunded balance – end of year $670 $3,400 $280 $115 $3,810 $235 6.09% for 2009 6.81% for 2010 6.91% for 2011 6.55% in 2009 8.50% in 2010 8.50% in 2011 A – Baseline Unfunded balance – end of year $140 $2,805 $240 $260 $2,680 $195 6.09% for 2009 7.00% for 2010 7.00% for 2011 8.50% in 2009 15.00% in 2010 8.50% in 2011 C – Accelerated equity recovery Unfunded balance – end of year $715 $5,190 $350 $445 $5,700 $315 6.09% for 2009 5.45% for 2010 5.63% for 2011 0% in 2009 0% in 2010 8.50% in 2011 D – Equity recovery in 2 years Unfunded balance – end of year Required contribution (1) Pre-tax expense Required contribution (1) Pre-tax expense Discount Rate Actual Asset Returns 2011 2010 Assumptions Illustrative Scenario ($ in millions) (1) The contributions shown above include estimated pension contributions required under
ERISA and the Pension Protection Act of 2006, as well as certain discretionary contributions necessary to avoid benefit restrictions. Also included within these amounts are expected
payments to Exelon’s non-qualified plans of approximately $5 million under Scenario A in both 2010 and 2011, and $15 million and $5 million under Scenarios B-D in 2010 and 2011, respectively. In Scenarios B-D, contributions reflect the impact of electing the option to smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008, as
well as a $350 million contribution discretionary made in the third quarter of 2009. Note: Slide provided for illustrative purposes and not intended to represent a forecast
of future outcomes. Assumes ~20% overall capitalization rate of pension costs. 2009 Expense: Exelon estimates pre-tax 2009 pension expense of $210 million and 2009 pension contributions of $440
million. |
 26 Potential Variability in Future OPEB Expense and Contributions $155 $2,535 $235 $155 $2,485 $230 6.09% for 2009 5.45% for 2010 5.63% for 2011 21.15% in 2009 8.50% in 2010 8.50% in 2011 B – Forecast as of September 30 Unfunded balance – end of year $155 $2,115 $205 $155 $2,050 $190 6.09% for 2009 6.81% for 2010 6.91% for 2011 6.50% in 2009 8.50% in 2010 8.50% in 2011 A – Baseline Unfunded balance – end of year $155 $2,065 $190 $155 $1,975 $185 6.09% for 2009 7.00% for 2010 7.00% for 2011 8.50% in 2009 15.00% in 2010 8.50% in 2011 C – Accelerated equity recovery Unfunded balance – end of year $155 $2,915 $285 $155 $2,840 $265 6.09% for 2009 5.45% for 2010 5.63% for 2011 0% in 2009 0% in 2010 8.50% in 2011 D – Equity recovery in 2 years Unfunded balance – end of year Estimated contribution (1) Pre-tax expense Estimated contribution (1) Pre-tax expense Discount Rate Actual Asset Returns 2011 2010 Assumptions Illustrative Scenario ($ in millions) 2009 Expense: Exelon estimates pre-tax 2009 OPEB expense of $210 million and 2009 OPEB contributions of $155 million. (1) The contributions shown above are subject to change and include approximately $5
million that is expected to be paid out of corporate assets. Note: Slide
provided for illustrative purposes and not intended to represent a forecast of future outcomes. Assumes ~20% overall capitalization rate of OPEB costs. |
 27 Climate Legislation Has 4 Key Components • Washington Advocacy: Exelon’s lobbyists, and key executives, are meeting with key senators and staff to drive toward comprehensive legislation • Coalitions: Working with United States Climate Action Partnership (USCAP), Edison Electric Institute, and Clean Energy Group to advance climate legislation • Grassroots: Mobilizing our employees, retirees, and shareholders • Media: Working with a diverse group of stakeholders on media opportunities in favor of climate legislation Exelon Advocacy Efforts Exelon continues to lead in advancing climate change legislation Price Collar Renewables/ Efficiency Allowances to LDCs Cap and Trade Note: LDCs = Local Distribution Companies |
 28 Source: Ventyx Velocity Suite Database Bubble size represents carbon intensity, expressed in terms of metric tons of CO2 per MWh generated 0 50 100 150 50 100 150 200 2008 Gross Generation (TWh) Exelon AEP Southern Duke TVA FPL Entergy Dominion Berkshire Hathaway Calpine NRG First Energy Xcel Ameren Progress 250 CO2 Intensity of Large Generators 15 Berkshire Hathaway 0.84 14 Ameren Corp 0.81 13 NRG Energy 0.78 12 AEP 0.77 11 Xcel Energy 0.74 10 Southern 0.69 9 Duke Energy 0.63 8 Progress Energy 0.61 7 TVA 0.60 6 FirstEnergy 0.55 5 Dominion 0.49 4 Calpine 0.39 3 FPL Group 0.33 2 Entergy 0.27 1 Exelon 0.06 (1) Exelon 2020 is Exelon’s comprehensive plan to reduce, displace or offset
15 million metric tons of greenhouse gas emissions each year by 2020. Exelon
2020 (1) will ensure that Exelon maintains and extends its position as the nation’s top low-carbon power generator Lowest Carbon Intensity of the Largest U.S. Generators CO2 Emissions of Largest US Electricity Generators |
 29 Value Return Framework Less Equals Maintenance Capital and Committed Dividends Cash Flow from Operations before Dividends and CapEx Strengthen Balance Sheet / Increase Financial Flexibility Invest in Growth Available Cash and Balance Sheet Capacity Return Value via Share Repurchases, Additional Dividends |
 30 Focusing on the Transmission Grid Across Exelon ComEd and PECO • Continued transmission investments focused in their service territories as required for reliability Exelon Transmission Company • Evaluating needed upgrades of the existing system to reduce constraints and improve power flow from our assets • Projects would include short-term modifications to existing infrastructure Exelon Generation • Invest in shovel ready projects with utilities • Pursue Extra High Voltage (EHV) development opportunities in and around our existing footprint including partnerships with Exelon utilities and regional developers • Expand focus beyond our footprint and evaluate partnering with renewable developers including merchant transmission |
 31 |
 32 Capitalizing on Market Opportunity and Exelon Expertise • $60-100 billion expected investment in U.S. over next 10 years • Opportunity for FERC-regulated returns and Construction Work in Progress incentives • Minimal required initial investment prior to regulatory approvals • Benefits of investment: – Improve reliability – Facilitate movement of renewable energy to population centers – Reduce congestion costs to customers • Separate LLC lends transparency to an eventual development and investment portfolio • Specialized expertise through dedicated management team • Leverage corporate experience and understanding of regulatory process • 2010 O&M start-up costs funded by Exelon, investments/development funded via project finance, as appropriate • Opportunity to invest in projects with traditional regulated frameworks and consider merchant transmission Market Opportunity Exelon Business Plan Investment in capital constrained projects with regulatory approvals Investments within existing footprint and partnerships Partnerships with renewable developers Merchant transmission investment Exelon Transmission Company (ETC) leverages existing capabilities and offers a
phased approach to disciplined, high-return growth Close-In Traditional Risk Profile Test and Learn Longer Cycle Time Change in Risk Profile Competitive Mind Set |
 33 Balanced Portfolio Investment Framework The Exelon Transmission Company portfolio will evolve over time Act as Transmission Investment Arm Transmission Options Tied to Footprint Partnerships with Transmission Developers Partnerships with Renewables Developers Pursue Merchant Transmission • Increasing number of utility sponsors are capital constrained • Early participation in projects at advanced development stage and relatively
fast participation in attractive FERC-regulated
incentive rate structures • Insiders’ view of development challenges outside our footprint • Assess existing investment model and opportunities in ComEd and PECO footprint to
address known, regional congestion issues and improve transmission
reliability • Decision to proceed as a stand-alone transmission company project, utility project
or joint venture to be made on case-by-case basis • Assess existing regional and national opportunities • Leverage participation in SMART Transmission study • Focus on markets with attractive fundamentals in 4 areas: regulatory, supply/demand, structural/RTO opportunities, local dynamics • Emerging opportunity to address transmission bottlenecks being experienced by developers • Identify and value merchant transmission opportunities in major markets • Creates competition to construct most efficient and lowest cost addition to the transmission grid |
 34 The New Crossroads of our Energy Future Illinois positioned to facilitate the movement of renewable energy to population
centers beyond Chicago |
 35 • Create extra-high voltage (EHV) overlay alternatives that ensure reliable service for our communities and are environmentally friendly • Find technically sound solutions for integrating renewables and new transmission into the existing system • Identify economic solutions that show the numerous benefits of transmission expansion American Transmission Company (ATC) American Electric Power (AEP) – via ETA MidAmerican Energy Holdings Company – via ETA Exelon Corporation MidAmerican Energy Company NorthWestern Energy Xcel Study Partners SMART Transmission Study SMART Transmission Study Collaborating with Partners Note: ETA = Electric Transmission America |
 36 Transmission Investment Is Attractive • Potential for attractive returns (1) – FERC granted ROEs (including incentives) historically range from 11.5% to 14.3% • Financing structures – Cash flows attractive to lenders and rating agencies • EPS accretive immediately – Rate base capitalization and Construction Work in Progress (CWIP) recovery begins prior to project completion (1) • Limited up-front investment required – Significant capital expenditures and equity injection does not occur until all required approvals are obtained and recovery is highly certain – ETC would not invest until cost allocation (“who pays”) is clear Attractive returns, accretive, and relatively low equity contribution requirements for a growth business (1) Subject to FERC approval. |
 37 Exelon’s recent success with the unique urban-based challenges of the West
Loop project provides us with the experience, resources, and technology to
be successful in long-haul EHV development Exelon Is Experienced in Transmission Investment • Own, operate and maintain >6,400 miles of transmission, including 90 miles of 765kV • $1 billion in high-voltage transmission system investment since 2003 • $5 billion in T&D investment since 2001 • Success with large and complex urban projects such as the ComEd Chicago West Loop Substation project – Completed in 2008, this $350 million initiative installed additional network capacity as part of the Chicago conversion from "hub and spoke" to a network design |
 38 |
 39 • Large, low-cost, low-emissions, exceptionally well-run nuclear fleet • Complementary and flexible fossil and hydro fleet • Leveraged to improving power market fundamentals (commodity prices, heat rates, and capacity values) • Below-market contract in Pennsylvania ends at year-end 2010 • Potential carbon restrictions Value Proposition Exelon Generation Value Proposition • Continue to focus on operating excellence, cost management, and market discipline • Execute on power and fuel hedging programs • Support competitive markets • Pursue nuclear & hydro plant relicensing and strategic investment in material condition • Maintain industry-leading talent Protect Value • Pursuing 1,300-1,500 MW nuclear uprate plan • Rigorously evaluate generation development opportunities • Capture increased value of low-carbon generation portfolio Grow Value Exelon Generation is the premier unregulated generation company – positioned to capture market opportunities and manage risk |
 40 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 2000 2001 2002 2003 2004 2005 2006 2007 2008 Basics of Business Unchanged Nuclear remains one of the lowest cost options for electricity production Petroleum Gas Coal Nuclear 1.87 U.S. Electricity Production Costs (2000-2008) (1) (1) In 2008 cents per kilowatt-hour. Source: NEI, Ventyx Velocity Suite May 2009. Production Cost = O&M plus fuel. 2.75 8.09 17.26 |
 41 A Leading Nuclear Fleet Operator in Cost Among major nuclear plant fleet operators, Exelon is consistently one of the
lowest-cost producers of electricity in the nation 0 5 10 15 20 25 1 st Quartile 2 nd Quartile 3 rd Quartile 4 th Quartile 2004-2008 Average Production Cost for Major Nuclear Operators (1) Average (1) Source: 2008 Electric Utility Cost Group (EUCG) survey. Includes Fuel Cost plus Direct O&M divided by net generation. |
 42 Effectively Managing Nuclear Fuel Costs Components of Fuel Expense in 2009 Projected Total Nuclear Fuel Spend Projected Exelon Average Uranium Cost vs. Market Projected Exelon Uranium Demand Note: At Ownership. Excludes costs reimbursed under the settlement agreement
with the DOE. 2009 – 2013: 100% hedged in volume 2014: ~93% hedged in volume All charts exclude Salem 0.0 2.0 4.0 6.0 8.0 10.0 2009 2010 2011 2012 2013 2014 0 200 400 600 800 1,000 1,200 1,400 2009 2010 2011 2012 2013 2014 Nuclear Fuel Expense (Amortization + Spent Fuel) Nuclear Fuel Capex 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2009 2010 2011 2012 2013 2014 Exelon Average Reload Price Projected Market Price (Spot) Enrichment 38% Fabrication 16% Nuclear Waste Fund 19% Tax/Interest 1% Conversion 3% Uranium 23% |
 43 0 20 40 60 80 100 120 140 160 Uranium Price Volatility Long-term equilibrium price expected to be $40-$60/lb Short-term Uranium Price Trend Long-term Uranium Price Trend Spring 2003 McArthur River flood December 2003 GNSS/Tenex termination; ConverDyn UF6 release and shutdown Early 2004 ERA / Ranger water problems Early 2006 First Cigar Lake flood; Cyclone Monica halts ERA / Ranger operations for approximately two weeks October 2006 Second Cigar Lake flood March 2007 ERA / Ranger flooding (cyclone George) 30 35 40 45 50 55 60 65 70 75 80 |
 44 World-Class Nuclear Operator Average Capacity Factor Note: Exelon data prior to 2000 represent ComEd-only nuclear fleet. # of Reactors per Operator represents as of 2008. Sources: Platt’s, Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy). 65 70 75 80 85 90 95 100 Operator (# of Reactors as of 2008) Range 5-Year Average Range of Fleet 2-Yr Avg Capacity Factor (2004-2008) EXC 93.8% Sustained production excellence 40% 50% 60% 70% 80% 90% 100% Exelon Industry |
 45 Impact of Refueling Outages 125 127 129 131 133 135 137 139 141 143 145 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 7 8 9 10 11 12 13 Note: Data includes Salem. Net nuclear generation data based on ownership interest. • Every 18 months (PWRs) or 24 months (BWRs) • Average Outage Duration: ~24 days (1) Nuclear Refueling Cycle • Based on the refueling cycle, we will conduct 10 refueling outages in 2010, the same number of refueling outages conducted in 2009 2010 Refueling Outage Impact Refueling Outage Duration Nuclear Output 0 10 20 30 40 50 60 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 YTD Exelon Industry (w/o Exelon) • Estimated output reflects TMI extended steam generator replacement outage • Based on the refueling cycle, we are conducting 10 refueling outages in 2009, versus 12 in 2008 2009 Refueling Outage Impact Actual Target Estimate # of Outages (1) Average Outage Duration for refueling outages from 2007 – 2008, excluding Salem. Note: Exelon data includes Salem. YTD includes completed refueling outages
through September 2009. |
 46 Nuclear Uprates Offer Sustainable Value Key component of Exelon 2020 low carbon roadmap Creates additional low-carbon generation capacity Capitalizes on Exelon’s proven track record of uprate execution Dedicated project management team Proven technology design No ongoing incremental O&M expense Creates long-term value over extended license lives Uprates equivalent in size to a new nuclear plant but significantly lower cost, shorter timeline, and more predictable spend Straightforward regulatory and environmental licenses, permits and approvals Potential for uprates to meet state alternative energy standards Uprate projects enable cost-effective growth and leverage Exelon’s operational excellence Strategic Value Grow Value Regulatory Feasibility Execution Feasibility |
 47 Three Major Categories of Exelon Uprates Uprates Overnight Cost (1) MUR (Measurement Uncertainty Recapture) • Through the use of advanced techniques and more precise instrumentation, reactor power can be more accurately calculated • Can achieve up to 1.7% additional output • Requires NRC approval 187–234 MW $300M 2 years 899–1,016 MW $2,400M EPU (Extended Power Uprate) • Through a combination of more sophisticated analysis and upgrades to plant equipment, uprates can increase output by as much as 20% of original licensed power level • Requires NRC approval 3 - 5 years 237–266 MW $800M Megawatt Recovery and Component Upgrades • Replacement of major components in the plant occur in the normal life cycle process – with newer technology, replacements result in increased efficiency • Equipment includes generators, turbines, motors and transformers • Megawatt Recovery and Component Upgrades must conform to NRC standards, but do not require additional NRC approval 2 - 3 years ~1,300–1,500 MW $3,500M Project Duration Exelon’s $2,200 – $2,500 / kW overnight cost for its MUR and EPU projects is an advantageous deployment of capital relative to other generation options (1) In 2007 Dollars. Overnight costs do not include financing costs or cost
escalation. Estimated Internal Rate of Return 12-15% 14-18% 9-12% |
 48 Phased Execution Lowers Risk • Safe, economical and proven methods to improve efficiency and output • Leverages Exelon’s substantial experience managing successful uprate projects over
the past 10 years Note: Data contained in this slide is rounded. Uprate program allows us to adjust timing to respond to market conditions EPUs MURs MW Recovery and Component Upgrades Maximum
Potential
MW Year Uprates Become Operational 1999- 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2009- 2017 Exelon’s Uprate Plan 1,100 MW 1,300 – 1,500 MW Average Overnight Cost Estimate: $2,200 - 2,500/KW 0 200 400 600 800 1,000 1,200 1,400 1,600 Planned Capital Spend (1) $150 2017 $625 2013 $675 2012 $550 2011 $350 2010 $725 2015 $725 2014 $400 2016 $4,425 2008 - 2017 $225 2008 - 2009
(1) Dollars shown are nominal, reflecting 6% escalation, in millions.
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  49 Uprates Across the Exelon Fleet Base Maximum Station Case Potential MW MW Braidwood - MUR 34 - 42 2012 Byron - MUR 34 - 42 2012 Clinton - EPU 17 - 17 2016 Clinton - EPU 2 - 3 2010 Dresden - MW Recovery & Component Upgrades 103 - 110 2012 Dresden - MW Recovery & Component Upgrades 5 - 5 2011 Dresden - MUR 25 - 31 2014 LaSalle - MUR 32 - 40 2011 LaSalle - EPU 303 - 336 2016 Limerick - MUR 33 - 41 2011 Limerick - MW Recovery & Component Upgrades 6 - 6 2012 Limerick - EPU 306 - 340 2017 Peach Bottom - MW Recovery & Component Upgrades 25 - 32 2012 Peach Bottom - EPU 134 - 148 2015 Peach Bottom - MW Recovery & Component Upgrades 3 - 3 2014 Quad Cities - MUR 19 - 23 2013 Quad Cities - MW Recovery & Component Upgrades 95 - 110 2011 TMI - EPU 138 - 172 2016 TMI - MUR 12 - 15 2014 Total 1,323 - 1,516 Year of Operation Uprates will largely be completed during scheduled refueling outages Note: MW shown at ownership. |
 50 Exelon Nuclear Fleet Overview Fleet also includes 4 shutdown units: Peach Bottom 1, Dresden 1, Zion 1 &
2. Average in-service time = 28 years 2011 42.6% Exelon, 56.4% PSEG In process (decision in 2011- 2012): 2016, 2020 503, 500 (2) W PWR 2 Salem, NJ Life of plant capacity 100% Renewed: 2034 837 B&W PWR 1 TMI-1, PA Dry cask 100% Renewed: 2029 625 GE BWR 1 Oyster Creek, NJ Dry cask 50% Exelon, 50% PSEG Renewed: 2033, 2034 574, 571 (2) GE BWR 2 Peach Bottom, PA Dry cask 75% Exelon, 25% Mid- American Holdings Renewed: 2032 655, 662 (2) GE BWR 2 Quad Cities, IL Dry cask 100% Renewed: 2029, 2031 869, 871 GE BWR 2 Dresden, IL 2010 100% 2022, 2023 1138, 1150 GE BWR 2 LaSalle, IL Dry cask 100% 2024, 2029 1148, 1145 GE BWR 2 Limerick, PA Re-rack completed 2011 2013 Spent Fuel Storage/ Date to lose full core discharge capacity GE W W Vendor BWR PWR PWR Type 1 2 2 Units 100% 2026 1065 Clinton, IL 100% 2024, 2026 1183, 1153 Byron, IL 100% 2026, 2027 1194, 1166 Braidwood, IL Ownership License Status / Expiration (1) Net Annual Mean Rating MW 2009 Plant, Location (1) Operating license renewal process takes approximately 4-5 years from commencement
until completion of NRC review. (2) Capacity based on ownership interest. Uprates + license extensions = long term value creation TMI license extension received in October 2009 |
 51 51 Total Portfolio Characteristics Expected Total Supply (GWh) Expected Total Sales (GWh) 92,000 91,400 47,700 48,400 29,200 27,100 4,500 4,500 0 50,000 100,000 150,000 200,000 2009E 2010E Forward / Spot Purchases Fossil & Hydro Mid-Atlantic Nuclear Midwest Nuclear 173,400 173,400 171,400 171,400 103,200 102,700 39,900 39,900 5,600 16,900 22,700 13,900 0 50,000 100,000 150,000 200,000 2009E 2010E ComEd Swap IL Auction PECO Load Actual Forward Hedges & Open Position |
 52 Energy Prices Are Driven by Fuel, but Influenced by Other Factors • Forward market prices suggest that natural gas will set the price about 15% of the time • PRB or eastern coal sets the price about 85% of the time Gas/coal prices are the primary price driver, but other factors such as demand, supply
and transmission constraints influence the portion of the time that gas
versus coal sets the market clearing price • Forward market prices suggest that natural gas will set the price about 40% of the time • Eastern coal sets the price about 60% of the time Midwest Energy & Fuel $0 $10 $20 $30 $40 $50 2007 2008 2009 2010 2011 2012 $0 $2 $4 $6 $8 Eastern Energy & Fuel $0 $10 $20 $30 $40 $50 $60 $70 2007 2008 2009 2010 2011 2012 $0 $2 $4 $6 $8 $10 Chicago Gas NiHub ATC PRB Coal Historical Forward Market PA Gas PJMW ATC NAPP Coal Forward Market Historical |
 53 Fuel and Demand Do Not Explain Midwest Forward Energy Prices • Forward markets suggest that gas and western coal prices over the next three years will
be slightly higher than over the past three years • Demand is also expected to be slightly higher • Yet Midwest forward prices are significantly lower than historical average spot
prices $34.26 $61.33 $10.95 $6.71 2010-2012 Average Forward (1) (16%) $40.68 NiHub ATC Price ($/MWh) +0.8% (3) ComEd Load (GWh) (10%) $68.30 NAPP Coal Price ($/ton) (2) +6% $10.30 PRB Coal Price ($/ton) (2) +2% $6.55 Chicago Gas Prices ($/MMBtu) (2) Forward Premium (Discount) 2007-2009 Average Spot Midwest forward market price is not consistent with fuel price and demand
increases (1) Forward prices as of September 30, 2009. (2) Fuel price effect on NiHub ATC price vary and assume all other price inputs
constant. (3) Reflects ComEd’s load growth in 2010. |
 54 Near-Term Wind Build Out Will Be Limited • Wind under construction (plus existing wind) is sufficient to meet state RPS
requirements through 2012 and other projects in the interconnection queue
have stalled • Based on bids we have received from developers, new wind needs roughly $50/MWh
above current Midwest market prices to be economic and very few buyers are willing
to pay such a price We expect no more than 3,000 MW of new wind to come online in west MISO and ComEd
over the next three years, impacting NiHub prices by less than $1/MWh (1) (1) Price impact will depend on location of new wind, as wind in west MISO will tend to have
less of an impact than wind in ComEd. Note: Graph includes MidAmerican
in MISO as of September 2009. |
 55 (1) Price impact will depend on location of new wind, as wind in west MISO will tend to have less of an
impact than wind in ComEd. Long-Term Wind Impact Will Be Moderate • Impact on Midwest prices will be moderate under most plausible scenarios for federal and
state mandates. – No Federal RPS • Full compliance with current state RPS would result in an additional 10 to 15 GW of
wind in west MISO/ComEd by 2020 which could reduce prices by $1/MWh to
$2/MWh in NiHub • Because of current economics of wind, partial compliance (either through purchase from other states or payment of price cap) is possible and this would result in impact at the
lower end of this range – Federal RPS and Carbon Legislation (similar to Waxman-Markey) • Without a significant transmission build out, 20 to 25 GW of wind in west MISO/ComEd
could materialize translating to a price impact in the $2/MWh to $3/MWh
range • With a transmission build out, price impact would only be above this range if it is
exclusively west of NiHub: – Transmission build out would increase wind in west MISO/ComEd to 25 to 30 GW – If build out west of NiHub continues east into AEP, then price impact would remain in
$2/MWh to $3/MWh range – If build out is west of NiHub only, despite favorable economics of east line, then
price impact could approach double this amount Based on our modeling of plausible wind scenarios, the long-term impact of Midwest
wind on NiHub prices is likely to be in the $2/MWh to $3/MWh range (1) |
 56 Implied Transmission Constraints Appear Overstated • Historically, NiHub prices have traded at a discount to AEP prices of $5/MWh or
less • Financial Transmission Rights (FTR) auction prices translate to a price discount of
about $6/MWh (including an assumption for marginal losses) – The FTR price represents a market-based view of the price difference between two
locations • But forward energy market suggests that NiHub discount will increase to $10/MWh
– This discount appears overstated given the anticipated return to service of the Cook nuclear station and the joint project between NIPSCO and Edison to address congestion issues on
NIPSCO’s transmission system Contrary to the current forward energy market, we believe that the NiHub discount
relative to AEP will not increase significantly in the next few years
(1) Forward prices as of September 30, 2009. (2) Reflects results of October 2009 PJM long-term FTR auction. AEP-Dayton / NI Hub ATC Energy Basis 0 2 4 6 8 10 12 2006 2008 2010 2012 2014 Historical Spot Prices FTR Auction Prices (2) Forward Energy Prices (1) |
 57 30 35 40 45 50 55 2010 2011 2012 2013 2014 We See Upside Potential in Midwest Forward Energy Markets • Increasing gas, coal, and demand will place upward pressure on Midwest energy
prices • New wind supply will have minimal impact in the next few years • Transmission constraints are unlikely to be more severe than over the past year
Midwest power markets have upside…2012 gross margin increases by ~$300 million
for each $5/MWh increase in NiHub ATC 9/30/09 Forward Prices NiHub ATC Prices Current opportunity Carbon opportunity assuming a $15/tonne price and Waxman- Markey allocations |
 58 Exelon Generation Is Capitalizing on the Opportunity • Hedging actions – Maintain ratable hedging philosophy, while utilizing flexibility: • Participate in Pennsylvania wholesale load solicitations • Explore bilateral transaction opportunities (e.g. ODEC) • Utilize power and natural gas put options • Transact retail sales through Exelon Energy – Allocate a portion of hedges to locations to take advantage of market views • Reduce congestion between Midwest generation and load centers/trading hubs – Working with the stakeholders in PJM and MISO to validate the market to market
coordination between PJM and MISO • Specifically, participating in the Wisconsin market to market study request to review
and determine validity of the PJM to MISO coordinated energy dispatch
• Working with several industry consultants (CRA and NorthBridge) to assist in the
review – Identify, analyze and value the limiting constraints on the transmission system that
directly impact the baseload value of our fleet • Focus areas include the Illinois / Indiana interface (Ni-Hub to AD Hub), central
Illinois (Clinton to Cinergy Hub) and Western Illinois (Quad
Cities/Byron to Ni-Hub) • Evaluate near-term impacts of Cook nuclear station returning to service and the
joint project between NIPSCO and Edison to address congestion issues on the
Illinois / Indiana interface – Prioritize economic transmission upgrades (that can be completed in the next five years) based on historical constraints and our fundamental view of the market
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 59 Reliability Pricing Model Auction PJM RPM Auction ($/MW-day) Exelon Generation Participation within PJM Reliability Pricing Model (1) Note: Data contained on this slide is rounded. 40.80 197.67 111.91 148.80 102.04 191.32 174.29 110.00 16.46 133.37 139.73 2007/2008 2008/2009 2009/2010 2010/2011 2011/2012 2012/2013 RTO MAAC + APS MAAC Eastern MAAC Only shown if cleared at separate price and generation is located in that zone (5) (1) All generation values are approximate and not inclusive of wholesale transactions.
(2) All capacity values are in installed capacity terms (summer ratings) located in the
areas. (3) Obligation consists of load obligations from PECO. PECO PPA expires December 2010.
(4) Obligation represents the remainder of the ComEd auction load that ends in May
2010. (5) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System. (6) Elwood contract expires in 12/31/12 and Kincaid contract expires in 2/28/13. (7) Weighted average $/MW-Day would apply if all generation cleared in the highlighted zones. 2009/2010 2010/2011 2011/2012 2012/2013 in MW Capacity (2) Obligation Capacity (2) Obligation Capacity (2) Capacity (2) RTO 12,800 3,800 - 4,100 (4) 23,900 9,300 - 9,400 (3) 23,200 12,100 (6) EMAAC 9,500 MAAC + APS 11,100 9,300 – 9,400 (3) MAAC 1,500 Avg ($/MW-Day) (7) $143.90 $174.29 $110.00 $74.75
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 60 Capacity Prices Should Start to Recover in Next Auction • Several factors will place upward pressure on capacity prices, particularly at the RTO
level: – Rule change pending at FERC allowing existing demand response to bid above $0 – Addition of FirstEnergy Ohio to PJM (FE Ohio peak load exceeds capacity obligation by
roughly 2,000 MW) (1) – Increase in coal plant costs and supply bids due to required environmental CapEx
Increasing capacity prices will provide Exelon with additional growth starting in
2013 0 25 50 75 100 125 150 175 200 2007-08 2008-09 2009-10 2010-11 2011-12 2012-13 2013-14 RTO EMAAC PJM RPM Auction Results (1) Based on FirstEnergy FERC filing which states that 2008 load was 12,972
MW (translates to a capacity obligation of 15,073 MW at a 16.2% reserve margin) compared to generation of 12,910 MW. |
 61 ~$5.50 $50.50 - $51.50 $28.50- $29.50 Estimated Build-Up of PECO Average Residential Full Requirements Price $91.60/MWh Full Requirements Costs ($/MWh) Average Full
Requirements Retail Sales Price (1) Load Shape & Ancillary Services $7.50 Capacity $12.00 Transmission & Congestion $7.00 - $8.00 Renewable Energy Credits $1.00 Migration, Volumetric Risk & Other $1.00 ~$6.50 (1) As provided by Exelon Generation. (2) On Oct 21, 2009 the Independent Evaluator (NERA) announced a wholesale winning bid
average price of $79.96/MWh for PECO’s Fall 2009 RFP (reflecting 17 & 29-month residential full requirements’ products with delivery beginning Jan 1, 2011). (1) As provided by Exelon Generation. (2) On Oct 21, 2009 the Independent Evaluator (NERA) announced a wholesale winning bid
average price of $79.96/MWh for PECO’s Fall 2009 RFP (reflecting 17 & 29-month residential full requirements’ products with delivery beginning Jan 1, 2011). Average Wholesale Energy Price $79.96 (2) 61 |
 62 62 Exelon Energy • Channel to market to execute Power Team hedging strategy – Exelon Energy retail aggregate load profile complements generation portfolio – Long term sales agreements with creditworthy customers reduce portfolio price and
earnings risk • Advocate for competitive markets – Provides customer benefits from competitively priced energy offerings • Channel to build relationship with end-use customers – Provides insight related to trends in demand and expectations for product and
services – Channel to provide products that support Exelon 2020 Plan and demand reduction
programs – Renewable Energy Credits (RECs) – Low Carbon Energy Certificates (EFECs) – Nuclear energy attributes transferred through PJM Generation Attribute Tracking
System – Demand Side Management Programs • Growth vehicle in regions that complement Exelon Generation footprint – Expansion opportunities into additional eastern PJM and ERCOT markets are under
evaluation • Supplies a wide range of energy and natural gas products directly to industrial
and commercial customers in Illinois, Pennsylvania, Michigan and Ohio Leveraging broad experience in wholesale markets and asset management through
integration with Power Team |
 63 Exelon Generation 2010 EPS Contribution Generation’s 2010 earnings are driven lower by market and portfolio
conditions (1) Estimated contribution to Exelon’s operating earnings guidance. $ / Share 2009 RNF O&M CTC/A/D Interest Expense Other 2010 $(0.32) $0.06 RNF O&M Other Depreciation & Amortization $(0.09) Key Items: Inflation
$(0.05) Pension/OPEB
$(0.06) Cost Savings
Initiative $0.04 2009E (1) 2010E (1) $2.55 - $2.80 $3.10 - $3.15 Key Items: Market/Portfolio Conditions/Generation $(0.29) Nuclear Fuel Expense $(0.12) PECO
CTC $(0.11) Capacity Market Prices $0.19 $(0.05) $(0.04) Interest Expense |
 64 64 Current Market Prices Units 2007 1 2008 1 2009 5 2010 6 2011 6 2012 6 PRICES (as of September 30, 2009) PJM West Hub ATC ($/MWh) 59.76 (2) 68.52 (2) 38.23 48.40 51.50 52.84 PJM NiHub ATC ($/MWh) 45.47 (2) 49.00 (2) 28.06 32.57 34.36 35.86 NEPOOL MASS Hub ATC ($/MWh) 66.72 (2) 80.56 (2) 41.69 58.22 62.91 64.50 ERCOT North On-Peak ($/MWh) 59.44 (3) 73.36 (3) 33.32 51.94 57.38 60.82 Henry Hub Natural Gas ($/MMBTU) 6.95 (4) 8.85 (4) 4.04 6.21 6.87 7.00 WTI Crude Oil ($/bbl) 69.72 (4) 104.49 (4) 57.26 73.86 77.16 79.11 PRB 8800 ($/Ton) 9.67 12.17 9.04 8.91 10.96 13.00 NAPP 3.0 ($/Ton) 47.54 105.36 52.03 55.03 63.00 66.00 ATC HEAT RATES (as of September 30, 2009) PJM West Hub / Tetco M3 (MMBTU/MWh) 7.68 6.97 8.04 6.96 6.76 6.83 PJM NiHub / Chicago City Gate (MMBTU/MWh) 6.65 5.57 6.99 5.22 5.00 5.12 ERCOT North / Houston Ship Channel (MMBTU/MWh) 7.80 7.42 7.79 7.36 7.28 7.54 (1) 2007 and 2008 are actual settled prices. (2) Real Time LMP (Locational Marginal Price). (3) Next day over-the-counter market. (4) Average NYMEX settled prices. (5) 2009 information is a combination of actual prices through September 30, 2009 and market
prices for the balance of the year. (6) 2010, 2011 and 2012 are forward market prices as of September 30, 2009.
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 65 65 65 65 45 55 65 75 85 95 105 115 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 20 25 30 35 40 45 50 55 60 65 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 35 45 55 65 75 85 95 105 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 5 6 7 8 9 10 11 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 65 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 $6.04 2011 $6.82 Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading
system. Quotes are daily. Forward NYMEX Coal 2010 $53.25 2011 $65.26 2010 Ni-Hub $43.06 2011 Ni-Hub $45.29 2011 PJM-West $63.88 2010 PJM-West $59.37 2010 Ni-Hub $24.40 2011 Ni-Hub $26.00 2011 PJM-West $42.28 2010 PJM-West $39.79 |
 66 66 66 66 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 14.5 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 8 8.2 8.4 8.6 8.8 9 9.2 9.4 9.6 9.8 10 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 35 40 45 50 55 60 65 70 75 80 85 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 5 6 7 8 9 10 11 10/08 11/08 12/08 1/09 2/09 3/09 4/09 5/09 6/09 7/09 8/09 9/09 10/09 66 Market Price Snapshot 2011 $8.66 2010 $8.65 2010 $50.68 2011 $57.42 2010 $5.86 2011 $6.63 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 $5.91 2011 $7.10 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder Rolling 12 months, as of October 15, 2009. Source: OTC quotes and electronic trading
system. Quotes are daily. |
 67 Exelon Generation Hedging Disclosures |
      68 68 68 Portfolio Management Objective Align Hedging Activities with Financial Commitments • Power Team utilizes several product types and channels to market • Wholesale and retail sales • Block products • Load-following products and load auctions • Put/call options • Exelon’s hedging program is designed to protect the long-term value of our generating fleet and maintain an investment-grade balance sheet • Hedge enough commodity risk to meet future cash requirements if prices drop • Consider: financing policy (credit rating objectives, capital structure, liquidity); spending (capital and O&M); shareholder value return policy • Consider market, credit, operational risk • Approach to managing volatility • Increase hedging as delivery approaches • Have enough supply to meet peak load • Purchase fossil fuels as power is sold • Choose hedging products based on generation portfolio – sell what we own • Heat rate options • Fuel products • Capacity • Renewable credits % Hedged High End of Profit Low End of Profit Open Generation with LT Contracts Portfolio Optimization Portfolio Management Portfolio Management Over Time |
 69 69 69 69 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 |
 70 70 70 2010 2011 2012 Estimated Open Gross Margin (millions) (1) $5,850 $5,950 $5,850 Open gross margin assumes all expected generation is sold at the Reference Prices listed below Reference Prices Henry Hub Natural Gas ($/MMBtu) NI-Hub ATC Energy Price ($/MWh) PJM-W ATC Energy Price ($/MWh) ERCOT North ATC Spark Spread ($/MWh) (2) $6.21 $32.57 $48.40 $(1.51) $6.87 $34.36 $51.50 $(1.94) $7.00 $35.86 $52.84 $(0.17) (1) 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. (2) 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 Based on September 30, 2009 market conditions |
 71 71 71 (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 2010 and 11 refueling outages in
2011 and 2012 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.5%, 92.8% and 92.8% in 2010, 2011 and 2012 at Exelon-operated
nuclear plants. These estimates of expected generation in 2011 and 2012 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. 2010 2011 2012 Expected Generation (GWh) (1) 166,800 164,900 165,100 Midwest 98,600 98,200 97,000 Mid-Atlantic 59,900 59,100 59,800 South 8,300 7,600 8,300 Percentage of Expected Generation Hedged (2) 88-91% 63-66% 32-35% Midwest 88-91 67-70 41-44 Mid-Atlantic 91-94 56-59 20-23 South 90-93 52-55 22-25 Effective Realized Energy Price ($/MWh) (3) Midwest $46.50 $44.50 $46.00 Mid-Atlantic $33.75 $60.50 $52.75 ERCOT North ATC Spark Spread $3.00 $4.25 $5.75 Generation Profile |
 72 72 72 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% 2010 $45 $(40) $40 $(35) $30 $(25) +/-$50 2011 $265 $(225) $185 $(175) $165 $(160) +/-$50 2012 $525 $(500) $285 $(280) $270 $(260) +/-$55 (1) Based on September 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. Exelon Generation Gross Margin Sensitivities (with Existing Hedges) |
 73 73 73 95% case 5% case $6,100 $6,500 $6,000 $8,200 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 2010 2011 2012 $4,600 $8,300 Exelon Generation Gross Margin Upside / Risk (with Existing Hedges) (1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the
5th and 95th percentile 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 ransactions and potential modeling changes. These ranges of approximate gross margin in 2011
and 2012 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, 2009.
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 74 74 74 Midwest Mid-Atlantic ERCOT Step 1 Start with fleetwide open gross margin $5.85 billion Step 2 Determine the mark-to-market value of energy hedges 98,600GWh * 89% * ($46.50/MWh-$32.57/MWh) = $1.22 billion 59,900GWh * 92% * ($33.75/MWh-$48.40/MWh) = $(0.81 billion) 8,300GWh * 91% * ($3.00/MWh-($1.51)/MWh) = $0.03 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: Illustrative Example of Modeling Exelon Generation 2010 Gross Margin (with Existing Hedges) $5.85 billion $1.22 billion + $(0.81 billion) + $0.03 billion $6.29 billion |
 75 |
 76 6.1 6.9 2.0 2.0 7.2 6.5 2.0 2.1 Transmission Distribution ComEd Regulatory Plan Executing Regulatory Recovery Plan ~9-10% ~47% ~10% ~ 48% ~8% ~46% Earned ROE Equity (1) 5.5% 45.4% $8.1 $8.5 $9.3 2008 2009E 2011 (Illustrative) (2) Average Annual Rate Base ($ in billions) ComEd’s earnings are expected to increase as regulatory lag is reduced over time through cost savings, the uncollectible rider and regular rate requests (1) Equity based on definition provided in most recent ICC distribution rate case order
(book equity less goodwill). (2) Provided solely to illustrate possible future outcomes that are based on a number of
different assumptions, including an ROE target, all of which are subject to uncertainties and should not be relied upon as a forecast of future results. • Driving efficiencies to reduce and control O&M costs and capital spending • Legislation passed to enable recovery of uncollectibles expense through a rider anticipated in Q1 2010 (retroactive to 2008) • Anticipate filing electric distribution rate case in 2010 • Benefiting from regular transmission updates through a formula rate plan • ICC approved Smart Meter pilot program and rider • Standard & Poor’s and Moody’s raised credit ratings in 3Q 2009 2010E $8.9 |
 77 Illinois Power Agency (IPA) RFP Procurement • On September 30, 2009, the IPA submitted an Updated Procurement Plan for the 2010/11 planning period • Similar to 2009, the Procurement Plan for the 2010/11 planning period includes the
procurement of monthly peak and off-peak standard wholesale block energy
products • The IPA’s Plan also calls for the procurement of 1,887,014 MWh of Renewable Energy
Credits NOTE: Chart is for illustrative purposes only. Data on this slide is
rounded. Next RFP to be held in Spring 2010 2009 RFP 2009 RFP 2010 RFP 2010 RFP 2011 RFP 2011 RFP 2011 RFP 2012 RFP 2012 RFP 2013 RFP Financial Swap Auction Contract Delivery Period Peak Off-Peak June 2010 - May 2011 5,390 4,538 June 2011 - May 2012 1,858 668 Volumes to be secured in 2010 IPA Procurement Event (GWh) Jun 2009 Jun 2010 Jun 2011 Jun 2012 Jun 2013 Jun 2014 |
 78 Financial Swap Agreement with Exelon Generation 3,000 $53.48 January 1, 2013 - May 31, 2013 3,000 $52.37 January 1, 2012 - December 31, 2012 3,000 $51.26 January 1, 2011 - December 31, 2011 3,000 $50.15 June 1, 2010 - December 31, 2010 2,000 $50.15 January 1, 2010 - May 31, 2010 2,000 $49.04 June 1, 2009 - December 31, 2009 1,000 $49.04 January 1, 2009 - May 31, 2009 1,000 $47.93 June 1, 2008 - December 31, 2008 Notional Quantity (MW) Fixed Price ($/MWH) Portion of Term • Market-based contract for ATC baseload energy only – Does not include capacity, ancillary services, or congestion • Supplies ~67% of ComEd’s Residential/Small C&I load for 2010/11 • Represents long-term contract with stable pricing for ComEd’s customers
Note: C&I = Commercial & Industrial |
 79 -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 09Q1 09Q2 09Q3 09Q4E 10Q1E 10Q2E 10Q3E 10Q4E -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% All Customer Classes Large C&I Residential Gross Metro Product (right axis) ComEd Load Trends Weather-Normalized Load Key Economic Indicators Note: C&I = Commercial & Industrial Weather-Normalized Load Year-over-Year (4) Chicago U.S. Unemployment rate (1) 10.5% 9.8% 2009 annualized growth in gross domestic/metro product (2) (3.7)% (2.6)% 7/09 Home price index (3) (14.2)% (13.3)% (1) Source: Illinois Dept. of Employment Security (October 2009) and U.S.
Dept. of Labor (October 2009) (2) Source: Moody’s Economy.com (September 2009) (3) Source: S&P Case-Shiller Index (4) Not adjusted for leap year effect. Q309 Q409E 2009E (4) 2010E Customer Growth (0.5)% (0.6)% (0.4)% 0.1% Average Use-Per-Customer 0.1% (0.7)% (0.9)% (0.1)% Total Residential (0.4)% (1.3)% (1.3)% 0.0% Small C&I (2.9)% (0.8)% (2.4)% 1.0% Large C&I (8.6)% (4.1)% (6.7)% 1.5% All Customer Classes (3.8)% (1.9)% (3.4)% 0.8% |
 80 ComEd Smart Meter Pilot and Stimulus Funding • Smart Meter Pilot (or Advanced Metering Infrastructure - AMI) – ICC approved on October 14, 2009 – 1-year pilot program for 131,000 smart meters and related programs – ~$70 million spend in 2009-2010 with recovery with regulated return for capital
investment expected to begin in 2010 through a rider • Smart Grid Solar Pilot Project – $5 million in stimulus funds for Smart Grid Solar Pilot – Pilot group of ~100 customers will receive solar systems and be placed on real-time
pricing and net metering programs – Goals are (1) to study how photovoltaic panels and energy storage affect reliability of
the distribution system, (2) to evaluate consumer response to price signals
and (3) to assess customer acceptance of new technologies • Green Vehicle Fleet – $4 million in stimulus funding awarded to ComEd to expand Green Vehicle Fleet and
Test Impact on Electric Grid – Will add up to 14 new hybrid and plug-in electric vehicles to fleet – Will deploy vehicle smart charging stations and evaluate impacts of vehicle charging while managing the electric load ComEd is pursuing a number of smart grid investments with regulated returns and stimulus funding |
 81 ComEd 2010 EPS Contribution (1) Estimated contribution to Exelon’s operating earnings guidance. (2) Excludes estimated impact of Rider EDA (Energy Efficiency and Demand Response
Adjustment) of $0.05 per share in 2010. (3) Primarily recovery of 2008 and 2009 uncollectible expense, of which approximately $0.07
per share will be included in Q1 2010 earnings. ComEd’s operating
earnings are expected to increase in 2010 primarily due to continued execution of its Regulatory Recovery Plan 2009E (1) Depreciation & Amortization Interest Expense $0.60 - $0.70 $0.50 – $0.55 $0.13 $0.07 $(0.02) 2010E (1) $ / Share $(0.01) $(0.03) Other RNF (2) O&M (2) Key Items: Uncollectible Rider (3) Weather
Key Items: Cost Savings Initiative $0.07 Bad debt (3) $0.05
Inflation $(0.02)
Pension/OPEB $(0.02)
$0.04 $0.05 |
 82 |
 83 2.7 2.8 3.0 3.2 0.5 0.5 0.5 1.1 1.1 1.1 1.2 0.6 2.0 1.3 0.4 Gas Competitive Transition Charge (CTC) Electric Transmission Electric Distribution PECO Regulatory Plan Actively Engaged in Transition • One of six companies to receive maximum federal stimulus award of $200 million for smart grid / smart meter program • Anticipate filing electric and gas rate cases in 2010 • Filed plans and programs with PAPUC to implement energy efficiency, demand response and smart meter provisions of Pennsylvania Act 129 (HB2200) • Transitioning through an orderly structure to market-based electric rates – Completed 2 of 4 planned power procurements to address post-transition supply beginning in 2011 ~9 – 11% Not applicable due to transition rate structure Rate Making ROE Equity ~50-53% $6.3 $5.7 $5.0 Average Annual Rate Base (1) ($ in billions) 2008 2009E 2011 (Illustrative) (2) PECO provides a solid ROE with a strong capital structure (1) Rate base as determined for rate-making purposes. (2) Provided solely to illustrate possible future outcomes that are based on a number of
different assumptions, all of which are subject to uncertainties and should not be relied upon as a forecast of future results. $5.1 2010E |
 84 PECO Procurement Results PECO has completed two of the four procurements for the power needed to serve its
residential customers beginning in 2011 • On September 23, 2009, the PAPUC approved the bids from PECO’s second RFP
Residential Sept RFP average price of $79.96/MWh (2) June RFP average price of $88.61/MWh (2) 49% of full requirements product procured 80 MW of block energy procured Small and Medium Commercial Sept RFP average blended price of $85.85/MWh (2) 24% of Small Commercial full requirements product procured 16% of Medium Commercial full requirements product procured 85% full requirements 15% full requirements spot Medium Commercial & Industrial (peak demand >100 kW but <= 500 kW) 100% full requirements spot Large Commercial & Industrial (peak demand >500 kW) 90% full requirements 10% full requirements spot 75% full requirements 20% block energy 5% energy only spot Products Small Commercial (peak demand <100 kW) Residential Customer Class PECO Procurement Plan (1) Total Procured (including June and September RFPs) Residential 23% of planned full requirements contracts (17 and 29-mo terms) 140 MW of baseload (24x7) block energy products (12, 24 and 60-mo duration) 40 MW of Jan-Feb 2011 on-peak block energy Small Commercial 36% of planned full requirements contracts (17 and 29-mo term) Medium Commercial & Industrial 42% of planned full requirements contracts (17-mo term) May 24, 2010 RFP (1) See PECO Procurement website (http://www.pecoprocurement.com) for additional details regarding PECO’s
procurement plan and RFP results. (2) Wholesale prices; no Small/Medium Commercial products were procured in the June RFP. |
 85 5.03 5.03 0.51 0.51 6.26 2.57 9.41 PECO Average Residential Electric Rates (1) Average of PECO’s residential rates. (2) Provided for illustration only. Represents 49% of PECO’s full requirements
residential procurement for 2011. (3) Average retail price for full requirements products. Full requirements product includes
load following energy, capacity, ancillary transmission services and Alternative Energy Portfolio Standard requirements. (4) Does not include energy efficiency or changes in distribution rates. 2011 2010 Energy / Capacity Competitive Transition Charge (CTC) Transmission Distribution 14.37¢ (1) Unit Rates (¢/kWh) Electric Restructuring Settlement ~4% (4) 14.95¢ (1) Assumptions Illustrative Rate Increase Based on PECO Residential Full Requirements Procurement Results (2) • 2011 illustrative residential rate based on a weighting of 26% on Spring 2009 Retail results, 23% on Fall 2009 Retail results, and future supply procurement estimated at Fall 2009 Results • Actual 2011 default service residential rate will reflect associated full requirements costs, block energy costs, and spot market purchases, all of which will be acquired through multiple procurements • Rates will vary by customer class • Retail rate components include line losses and gross receipts taxes Spring 2009 10.13¢/kWh PECO Residential Procurement Results (3) Effect of Spring and Fall 2009 Procurements Fall 2009 9.16¢/kWh Retail Results |
 86 PECO Load Trends Weather-Normalized Electric Load Key Economic Indicators Weather-Normalized Load Year-over-Year (3) Philadelphia U.S. Unemployment rate (1) 8.5%
9.8% 2009 annualized growth in gross domestic/metro product (2) (3.4)%
(2.6)% (1) Source: U.S Dept. of Labor (PHL August 2009, US – October 2009) (2) Source: Moody’s Economy.com (September 2009) (3) Not adjusted for leap year effect. Note: C&I = Commercial & Industrial Q309 Q409E 2009E (3) 2010E Customer Growth (0.4)% (0.4)% (0.3)% 0.0% Average Use-Per-Customer (5.1)% (0.4)% (2.2)% (0.5)% Total Residential (5.5)% (0.8)% (2.5)% (0.6)% Small C&I (5.1)% (3.4)% (2.7)% (0.8)% Large C&I (2.2)% (1.7)% (3.0)% (2.3)% All Customer Classes (3.9)% (1.8)% (2.7)% (1.3)% -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% 09Q1 09Q2 09Q3 09Q4E 10Q1E 10Q2E 10Q3E 10Q4E -10.0% -7.5% -5.0% -2.5% 0.0% 2.5% 5.0% 7.5% 10.0% All Customer Classes Large C&I Residential Gross Metro Product (right axis) |
 87 PECO Smart Grid/Smart Meter • PECO intends to spend up to $650 million on its Smart Grid/Smart Meter Infrastructure (1) – $550 million Advanced Metering Infrastructure over 10 – 15 years – ~$300 million in 2010-2012 period – $100 million for Smart Grid over 3 years with stimulus funding • Awarded $200 million Federal Stimulus Grant on October 27 • Smart Meter investment required by Act 129, which provides for recovery through
surcharge including a return on capital investment • Smart Grid investment to be recovered through transmission and distribution rates
($ millions pre-tax) 2010 2011 2012 Total Act 129 Smart Meter Expanded Initial Deployment (600K meters by 2012) 40 $ 150 $ 100 $ 290 $ Smart Grid Stimulus Case 50 45 15 110 Total Stimulus Case 90 195 115 400 Stimulus Grant Request (45) (100) (55) (200) Total Expenditures net of Stimulus grant 45 $ 95 $ 60 $ 200 $ 2010-2012 Spend With Federal Stimulus Grant (2) : (3) (1) Does not include $100 million for potential replacement of gas meters and wind-down of legacy Automated
Meter Reading system. (2) Assumes 100% of matching funds requested by DOE. (3) Includes approximately $10 million, $15 million, and $25 million of O&M in 2010-2012, respectively.
Data contained in this slide is rounded. |
 88 PECO 2010 EPS Contribution PECO’s 2010 EPS contribution remains relatively flat to 2009 $ / Share RNF $(0.12) $0.45 - $0.50 (1) Depreciation & Amortization 2010E (2) Key Items: CTC $0.11 Weather $0.04 Load $(0.03) Key Items: Inflation $(0.02) Pension/OPEB $(0.01) $0.08 O&M $0.03 $0.40 - $0.50 (1) Key Items: CTC Amortization $(0.11) Interest $(0.03) Key Items: CTC Interest Expense $0.06 2009E (2) (1) Excludes preferred dividends. (2) Estimated contribution to Exelon’s operating earnings guidance.
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 89 Key Assumptions, Projected 2010 Credit Measures & GAAP Reconciliation |
 90 90 Key Assumptions 2008 Actual 2009 Est. (5) 2010 Est. (6) Nuclear Capacity Factor (%) (1) 93.9 93.6 93.5 Total Generation Sales Excluding Trading (GWh) 176,174 173,400 171,400 Total Generation Sales to PECO (GWh) 40,966 39,900 39,900 Total Generation Market and Retail Sales (GWh) (2) 135,208 133,500 131,500 Henry Hub Gas Price ($/mmBtu) 8.85 4.04 6.21 PJM West Hub ATC Price ($/MWh) 68.52 38.23 48.40 Tetco M3 Gas Price ($/mmBtu) 9.83 4.76 6.95 PJM West Hub Implied ATC Heat Rate (mmbtu/MWh) 6.97 8.04 6.96 NI Hub ATC Price ($/MWh) 49.00 28.06 32.57 Chicago City Gate Gas Price ($/mmBtu) 8.79 4.02 6.23 NI Hub Implied ATC Heat Rate (mmbtu/MWh) 5.57 6.99 5.22 PJM East Capacity Price ($/MW-day) 169.09 173.73 181.34 PJM West Capacity Price ($/MW-day) 82.39 106.13 144.40 Electric Delivery Growth (%) (3) PECO 0.6 (1.8) (1.3) ComEd (0.1) (3.4) 0.8 Effective Tax Rate (%) (4) 36.1 37.5 35.8 (1) Excludes Salem. . (2) Includes Illinois Auction sales and ComEd swap. (3) Weather-normalized retail load growth. (4) Starting on January 1, 2011, effective tax rate is expected to increase to 37.1% due to
lower tax benefit related to the PECO PPA roll off. (5)
2009 information is a combination of actual prices through September 30, 2009 and market prices for the balance of the year. (6) Reflects forward market prices as of September 30, 2009.
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 91 Projected 2010 Key Credit Measures 13.8x 8.1x FFO / Interest Generation / Corp: 62% 34% FFO / Debt 53% 68% Rating Agency Debt Ratio BBB A- A- BBB- S&P Credit Ratings (3) BBB+ A BBB BBB+ Fitch Credit Ratings (3) A3 A2 Baa1 Baa1 Moody’s Credit Ratings (3) 3.7x 3.8x FFO / Interest ComEd: 18% 14% FFO / Debt 42% 49% Rating Agency Debt Ratio 5.2x 5.0x FFO / Interest PECO: 28% 23% FFO / Debt 46% 50% Rating Agency Debt Ratio 29% 47% Rating Agency Debt Ratio 87% 44% FFO / Debt 18.6x 9.9x FFO / Interest Generation: 46% 37% 7.2x Without PPA & Pension / OPEB (2) 57% Rating Agency Debt Ratio 25% 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) FFO/Debt metrics include the following standard adjustments: 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 October 23, 2009. |
 92 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 + ComEd Transition Bond Principal Balance + 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 (1) Uses current year-end adjusted debt balance. (2) Metrics are calculated in presentation unadjusted and adjusted for debt equivalents and
related interest for PPAs, unfunded Pension and OPEB obligations, and Capital Adequacy for Energy Trading. (3) Reflects depreciation adjustment for PPAs and decommissioning interest income and
contributions. |
 93 2008 GAAP Reconciliation (0.22) - - (0.01) (0.21) 2007 Illinois electric rate settlement (0.02) - - (0.02) - City of Chicago settlement with ComEd (0.02) (0.02) - - - NRG acquisition costs 0.03 - - - 0.03 Resolution of tax matters at Generation related to Sithe 0.02 - - - 0.02 Decommissioning obligation reduction $4.13 $(0.10) $0.49 $0.30 $3.44 2008 GAAP Earnings (Loss) Per Share $4.20 $(0.08) $0.49 $0.33 $3.46 2008 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share 0.41 - - - 0.41 Mark-to-market adjustments from economic hedging activities (0.27) - - - (0.27) Unrealized losses related to nuclear decommissioning trust funds Exelon Other PECO ComEd Generation 2008 GAAP EPS Reconciliation (1) (1) Amounts shown are per Exelon share and represent contributions to Exelon's
EPS. Note: Amounts may not add due to rounding. (145) - - (7) (138) 2007 Illinois electric rate settlement 20 - - - 20 Resolution of tax matters at Generation related to Sithe 272 - - - 272 Mark-to-market adjustments from economic hedging activities 15 - - - 15 Decommissioning obligation reduction (11) (11) - - - NRG acquisition costs $(67) - - $(56) Other $2,737 (11) (184) $2,781 Exelon $325 - - $325 PECO $201 (11) - $219 ComEd Generation 2008 GAAP Earnings Reconciliation (in millions) - City of Chicago settlement with ComEd $2,278 2008 GAAP Earnings (Loss) (184) Unrealized losses related to nuclear decommissioning trust funds $2,293 2008 Adjusted (non-GAAP) Operating Earnings (Loss) |
 94 2009/2010 Earnings Outlook • Exelon’s outlook for 2009/2010 adjusted (non-GAAP) operating earnings 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
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 • Costs incurred for employee severance related to the cost reduction program announced in
June 2009 • Costs associated with early debt retirements • External costs associated with the terminated offer to acquire NRG Energy, Inc.
• Non-cash remeasurement of income tax uncertainties and reassessment of state
deferred income taxes • Other unusual items • Significant future changes to GAAP • Both our operating earnings and GAAP earnings guidance are based on the assumption of normal weather |
 95 Exelon Investor Relations Contacts Exelon Investor Relations 10 South Dearborn Street Chicago, Illinois 60603 312-394-2345 312-394-4082 (Fax) For copies of other presentations, annual/quarterly reports, or to be added to our email distribution list please contact: Martha Chavez, Executive Admin Coordinator 312-394-4069 Martha.Chavez@ExelonCorp.com Investor Relations Contacts: Karie Anderson, Vice President 312-394-4255 Karie.Anderson@ExelonCorp.com Stacie Frank, Director 312-394-3094 Stacie.Frank@ExelonCorp.com Paul Mountain, Manager 312-394-2407 Paul.Mountain@ExelonCorp.com Marybeth Flater, Manager 312-394-8354 Marybeth.Flater@ExelonCorp.com |