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
March 10, 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 March 10, 2009, at 12:00pm Eastern Daylight Time, Exelon Corporation (Exelon) will host the 2009 Exelon Investor Conference and will reaffirm its adjusted (non-GAAP) operating earnings guidance range for 2009 at $4.00 to $4.30 per share. The Exelon Investor Conference is available via webcast on the Exelon website at www.exeloncorp.com (please select the Investor Relations page). Attached as Exhibit 99.1 to this Current Report on Form 8-K are the handout materials 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 | Conference Handout Materials |
* * * * *
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; and (2) 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/ Robert K. McDonald |
| Robert K. McDonald |
| Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer |
| Commonwealth Edison Company |
| PECO ENERGY COMPANY |
| /s/ Phillip S. Barnett |
| Phillip S. Barnett |
| Senior Vice President and Chief Financial Officer |
| PECO Energy Company |
March 10, 2009
EXHIBIT INDEX
| Exhibit No. |
Description | |
| 99.1 | Conference Handout Materials |
 Exhibit 99.1 |
 2 Important Information This presentation relates, in part, to the offer (the “Offer”) by Exelon
Corporation (“Exelon”) through its direct wholly-owned subsidiary, Exelon Xchange Corporation (“Xchange”), to exchange each issued and outstanding share of common stock (the “NRG shares”) of NRG Energy, Inc. (“NRG”) for 0.485 of a share of Exelon common stock. This presentation is for informational purposes only and does not constitute an offer to exchange, or a solicitation of an offer to exchange, NRG shares, nor is it a substitute for the Tender Offer Statement on Schedule TO or the Prospectus/Offer to Exchange included in the Registration Statement on Form S-4 (Reg. No. 333-155278) (including the Letter of Transmittal and related documents and as amended from time to time, the “Exchange Offer
Documents”) previously filed by Exelon and Xchange with the Securities
and Exchange Commission (the “SEC”). The Offer is made only through the Exchange Offer Documents. Investors and security holders are urged to read these documents and other relevant materials as they become
available, because they will contain important information. Exelon expects to file a proxy statement on Schedule 14A and other relevant
documents with the SEC in connection with the solicitation of proxies
(the “NRG Meeting Proxy Statement”) for the 2009 annual meeting of NRG stockholders (the “NRG Meeting”). Exelon will also file a proxy statement on Schedule 14A and other relevant documents with the SEC in
connection with its solicitation of proxies for a meeting of Exelon
shareholders (the “Exelon Meeting”) to be called in order to approve the issuance of shares of Exelon common stock pursuant to the Offer (the “Exelon Meeting Proxy Statement”). Investors and security holders are urged to read the NRG Meeting Proxy Statement and the Exelon Meeting Proxy Statement and other relevant materials as they become available,
because they will contain important information. Investors and security holders can obtain copies of the materials described above (and
all other related documents filed with the SEC) at no charge on the SEC’s website: www.sec.gov. Copies can also be obtained at no charge by directing a request for such materials to Innisfree M&A Incorporated, 501 Madison Avenue, 20th Floor, New York, New York 10022, toll
free at 1-877-750-9501. Investors and security holders may also
read and copy any reports, statements and other information filed by Exelon, Xchange or NRG with the SEC, at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at
1-800-SEC-0330 or visit the SEC’s website for further information on its public reference room. Exelon, Xchange and the individuals to be nominated by Exelon for election to NRG’s
Board of Directors will be participants in the solicitation of proxies from
NRG stockholders for the NRG Meeting or any adjournment or postponement thereof. Exelon and Xchange will be participants in the solicitation of proxies from Exelon shareholders for the Exelon Meeting or any
adjournment or postponement thereof. In addition, certain directors and
executive officers of Exelon and Xchange may solicit proxies for the Exelon Meeting and the NRG Meeting. Information about Exelon and Exelon’s directors and executive officers is available in Exelon’s
proxy statement, dated March 20, 2008, filed with the SEC in connection with Exelon’s 2008 annual meeting of shareholders. Information about Xchange and Xchange’s directors and executive officers is available in Schedule II to the Prospectus/Offer to Exchange. Information about
any other participants will be included in the NRG Meeting Proxy Statement
or the Exelon Meeting Proxy Statement, as applicable. |
 3 Forward-Looking Statements This presentation includes forward-looking statements. There are a number of
risks and uncertainties that could cause actual results to differ materially
from the forward-looking statements made herein. The
factors that could cause actual results to differ materially from these forward-looking statements include those discussed in (1) Exelon’s 2008 Annual Report on Form 10-K in (a)
ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations and (c) ITEM 8. Financial
Statements and Supplementary Data: Note 18; (2) the Exchange Offer
Documents; and (3) other factors discussed in Exelon’s filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements, which
apply only as of the date of this filing. Exelon does not undertake
any obligation to publicly release any revision to its forward-looking
statements to reflect events or circumstances after the date of this filing, except as required by law. Statements made in connection with the exchange offer are not subject to the safe harbor
protections provided to forward-looking statements under the Private
Securities Litigation Reform Act of 1995. |
 4 4 Our Sustainable Advantage Remains |
 5 The Exelon Companies ’08 Earnings: $2,293M ’08 EPS: $3.46 Total Debt (1) : $2.5B Credit Rating (2) : BBB Nuclear, Fossil, Hydro & Renewable Generation Power Marketing ‘08 Operating Earnings: $2.8B ‘08 EPS: $4.20 Assets (1) :
$47.8B Total Debt (1) : $13.2B 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 December 31, 2008. (2) Standard & Poor’s senior unsecured debt ratings for Exelon and Generation and
senior secured debt ratings for ComEd and PECO as of February 27, 2009. Pennsylvania Utility Illinois Utility ’08 Earnings: $219M $325M ’08 EPS: $0.33 $0.49 Total Debt (1) : $5.0B $3.4B Credit Ratings (2) : BBB+ A- |
 6 Multi-Regional, Diverse Company Note: Owned megawatts based on Generation’s ownership at December 31, 2008, using annual mean ratings for nuclear units (excluding Salem) and summer ratings for Salem and the fossil and hydro units. 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 |
 7 Well-Positioned in Near-Term Macroeconomic Uncertainty • Hedging strategy provides near-term earnings and cash flow stability • Over 90% and ~90% financially hedged in 2009 and 2010, respectively Risk management • Proven management team • Lowest-cost nuclear fleet operator with ~94% capacity factor Best-in-class management / operations • Nuclear remains a low-cost generation source • Improving utilities’ performance and regulatory environment Basics of business unchanged • Nation’s largest nuclear fleet ~140,000 GWhs of annual production Market leader • Progress made on transition to competitive markets in PA • ComEd on path to regulatory recovery • Positively levered to long-term fundamentals Long-term value in place • Strong and consistent cash flows from operations (2) : ~$4.75 billion estimated in 2009 • Over 12% annual growth rate in dividend since 2001 Stable cash flows and commitment to value return • ~$6.8 billion of available credit facilities as of 2/27/2009 • Debt maturities of $29 million (1) , in total, through 12/31/2009 Sufficient liquidity Investment Criteria Exelon Profile (1) Excludes securitization debt and includes capital leases. (2) Cash Flow from Operations = Primarily includes net cash flows provided by operating
activities, excluding counterparty collateral activity, and including net cash flows used in investing activities other than capital expenditures. |
 8 2009 Operating Earnings Guidance 2009E 2008A $0.49 $3.46 $4.20 ComEd PECO Exelon Generation ComEd distribution revenue PECO gas revenue O&M and other Pension/OPEB Inflation Cost reduction initiatives Bad debt expense Nuclear fuel costs Depreciation and amortization PECO CTC 2009 Earnings Drivers ComEd PECO Exelon Generation Holdco Holdco Exelon $0.33 Exelon $4.00 - $4.30 (1) $0.45 - $0.55 $0.45 - $0.55 $3.10 - $3.35 (1) Adjusted (non-GAAP) Operating Earnings Guidance. Excludes the earnings impact of certain items as disclosed in the Appendix. Note: A = Actual; E = Estimate Reaffirming 2009 operating earnings guidance of $4.00-$4.30/share (1) – expect 1Q09 results between $1.10 to $1.20/share |
 9 Exelon Cost and Capital Management We are forecasting $150 million of sustainable O&M reductions in 2009; to date, approximately $100 million has been identified • Reducing nuclear outage expenses • Focusing on inventory management and reducing inventory growth • Right-sizing business unit administrative functions • Reducing capital spend for decreased new business requirements and declining load growth • Executing "ComEd Sustainable Solutions", "Engineering Excellence", "Operational Excellence" and "Putting Customers First" • Reducing new business and potential deferred capacity spend • Implementing “Productivity Improvement Cost Reduction” program • Executing credit and collections initiatives Intelligently reduce costs while maintaining superior operations • Optimizing the Exelon governance structure to drive efficiency, accountability, and
costs • Driving a consistent focus on productivity throughout the operating companies
• Executing rapid resourcing of Exelon’s $3.5B+ in external spend • Reviewing and reducing discretionary spend (consulting, travel, etc.) • Improving Exelon’s financial systems, contributing to improved staff
productivity |
 10 ~1% (2) $1,050 $1,100 ~3% (2) $700 $750 ~3% ~4% 2009-2013 CAGR $4,500 $2,750 2009E $4,500 $2,700 2008A Exelon (3) O&M Expense (1) ($ in Millions) O&M and CapEx Expectations ($ in Millions) ~1% (5) $850 $950 ~4% $400 $400 Exelon (3) ~3% ~9% ~(3%) 2009-2013 CAGR (4) $3,300 $900 $1,050 2009E $3,200 $800 $950 2008A Nuclear Fuel Plant & Other CapEx A combination of company-wide cost-savings initiatives and controlled spending
will offset inflationary pressures and rising pension and retiree health and welfare costs (1) Reflects Operating O&M data and excludes Decommissioning impact. (2) For ComEd and PECO, O&M excludes energy efficiency spend recoverable under a rider.
2009-2013 Compound Annual Growth Rate (CAGR) would be ~3% for ComEd and
~4% for PECO if spend were included. (3) Includes eliminations and other corporate entities. (4) Subject to change based upon proposed NRG acquisition. (5) ComEd CAGR assumes New Business expenditures remain at current
levels; only includes pilot program implementation of automated metering infrastructure (AMI) and does not include full scale Smart Grid implementation.
|
 11 2009 Pension and OPEB Expense and Contributions Cash Contributions $0 $50 $100 $150 $200 $250 Pension OPEB Pre-Tax Expense $0 $50 $100 $150 $200 $250 Pension OPEB Pension and OPEB Plans Key Metrics – 12/31/08E ($ in millions) Pension Assets $6,650 Obligations $10,800 2009E 2008 $85 $200 $160 $225 $80 $175 $163 $155 2009E 2008 (1) Excludes settlement charges. (2) Management has not yet made a definitive decision regarding its 2009 pension contributions and may make additional discretionary contributions based upon final interpretations of the Worker, Retiree and Employer Recovery Act of 2008. (3) Management has not yet made a definitive decision regarding its 2009 OPEB
contributions. Approximately $100 million of the estimated 2009 OPEB contributions is discretionary. Contributions shown above include contributions paid out of
corporate assets. Note: OPEB = other postretirement benefits; EROA = expected
return on assets (1) (2) (3) OPEB Assets $1,200 Obligations $3,500 Key Metrics 2008 asset return -26% 12/31/08 discount rate 6.09% L-T EROA 8.50% |
 12 Potential Variability in Future Pension Expense and Contributions $700 $3,730 74% $300 $130 $4,190 64% $260 6.09% for 2009 6.19% for 2010 6.26% for 2011 8.5% in 2009-2011 A- Asset returns at long-term rate Unfunded balance – end of year ERISA funded percentage (1) $1,175 $4,735 64% $320 $960 $5,570 61% $285 6.09% for 2009 6.19% for 2010 6.26% for 2011 -15% in 2009 -3% in 2010 8.5% in 2011 D- 2 years of low asset returns Unfunded balance – end of year ERISA funded percentage (1) $1,020 $4,510 66% $330 $205 $5,210 60% $275 6.09% for 2009 6.19% for 2010 6.26% for 2011 0% in 2009 0% in 2010 8.5% in 2011 C- Equity recovery in 2 years Unfunded balance – end of year ERISA funded percentage (1) $640 $2,770 74% $270 $155 $3,525 64% $220 6.09% for 2009 7.00% for 2010 7.00% for 2011 0% in 2009 15% in 2010 15% in 2011 B- Equity recovery Unfunded balance – end of year ERISA funded percentage (1) Required contribution (2) Pre-tax expense Required contribution (2) Pre-tax expense Discount Rate Actual Asset Returns 2011 2010 Assumptions Illustrative Scenario (1) The net funded percentage (used to amortize future contribution requirements) at the end
of 2010 is 60%, 60%, 60% and 61% under Scenarios A-D, respectively. (2) 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. Exelon also expects to make payments related to its non-qualified plans of approximately $22 million and $9 million in 2010 and 2011, respectively. Contributions reflect the impact of electing the option to
smooth asset returns provided under the Worker, Retiree and Employer Recovery Act of 2008. Note: Slide provided for illustrative purposes and not intended to represent a forecast
of future outcomes. Assumes 20% overall capitalization rate of pension and OPEB costs. Other Postretirement Benefits (OPEB) 2010 Expense: Exelon estimates pre-tax 2010 OPEB expense of
~$220 million, $200 million, $235 million and $260 million under Scenarios A-D, respectively. 2010 Contributions: Exelon estimates roughly $150 million of
contributions to its OPEB plans in 2010, which is subject to change. ($ in
Millions) |
 13 2009 Projected Sources and Uses of Cash $1,050 $800 $350 $250 Cash Available before Dividend 100 0 350 0 Other (400) 0 (150) 0 Net Financing (excluding Dividend): (2) 250 0 250 0 Planned Debt Issuances Net Financing (excluding Dividend): (2) (750) 0 (750) 0 Planned Debt Retirements (3) $4,750 $2,750 $900 $1,100 Cash Flow from Operations (1) (3,300) (1,950) (400) (850) Capital Expenditures $1,400 Dividend (4) Exelon (5) ($ in Millions) Numbers are rounded and may not add. (1) Cash Flow from Operations = Primarily includes net cash flows provided by operating
activities, excluding counterparty collateral activity, and including net cash flows used in investing activities other than capital expenditures. (2) Net Financing (excluding Dividend) = Net cash flows used in financing activities
excluding dividends paid on common and preferred stock. (3) Planned Debt Retirements are $17M, $728M, and $12M for ComEd, PECO, and ExGen,
respectively. Includes securitized debt. (4) Assumes 2009 Dividend of $2.10 per share. Dividends are subject to declaration by the board of directors. (5) Includes cash flow activity from Holding Company, eliminations, and other corporate
entities. |
 14 Sufficient Liquidity (1) Excludes previous commitment from Lehman Brothers Bank. (2) Available Capacity Under Facilities represents the unused bank commitments
under the borrower’s credit agreements net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit
agreements. (3) Includes cash flow activity from Holding Company,
eliminations, and other corporate entities. (150) -- -- (150) Outstanding Facility Draws (325) (124) (55) (141) Outstanding Letters of Credit $7,317 $4,834 $574 $952 Aggregate Bank Commitments (1) 6,842 4,710 519 661 Available Capacity Under Facility (2) (110) -- -- -- Outstanding Commercial Paper $6,732 $4,710 $519 $661 Available Capacity Less Outstanding Commercial Paper Exelon (3) ($ in Millions) We have minimal commercial paper outstanding and our bank facilities are largely
untapped Available Capacity Under Bank Facilities as of February 27,
2009 |
 15 Large and Diverse Bank Group Exelon has a large and diverse bank group with over $7.3 billion in aggregate credit facility commitments – 23 banks committed to the facilities with each bank having less than 10% of the aggregate commitments at Exelon • Bank of America, N.A. / Merrill Lynch USA (2) • The Royal Bank of Scotland PLC (RBS) • Barclays Bank PLC • JP Morgan Chase Bank, N.A. • The Bank of Nova Scotia (Scotia) • Wachovia Bank, N.A. • Citibank, N.A. • Commerzbank AG • BNP Paribas • Deutsche Bank AG, New York Branch • Credit Suisse, Cayman Islands Branch • Morgan Stanley Bank • UBS Loan Finance LLC • The Bank of New York / Mellon Bank, N.A. • Mizuho Corporate Bank, LTD • Goldman Sachs (3) • The Bank of Tokyo-Mitsubishi UFJ, LTD • KeyBank N.A. • U.S. Bank, N.A. • SunTrust Bank • The Northern Trust Company • Malayan Banking Berhad (May Bank) • National City Bank (1) As of February 27, 2009. (2) Assumes that Bank of America assumes Merrill Lynch’s previous commitment.
(3) Includes funding commitments by Williams Street Commitment Corporation, Williams Street Credit Corporation, Goldman Sachs Credit Partners, L.P. Banks Committed to Exelon’s Facilities (1) |
 16 $0 $150 $300 $450 $600 $750 2009 2010 2011 2012 2013 Exelon Corp Exelon Generation ComEd PECO 2009-2013 Debt Maturities Note: Balances shown exclude securitized debt and includes capital leases. Minimal debt maturities before 2011 $29 M Total $615 M Total $1,800 M Total $827 M Total $554 M Total |
 17 Factors Impacting 2011 Earnings Outlook PJM W-Hub ATC Price: +/- $5/MWh +/- $0.25 ComEd ROE: +/- 0.5% +/- $0.03 2011 EPS Sensitivities Volatility Risk Factors NI-Hub ATC Price: +/- $5/MWh +/- $0.25 PECO ROE: +/- 0.5% +/- $0.02 O&M CAGR: +/- 1% +/- $0.10 Uranium Prices: +/- $25/lb +/- $0.01 ExGen Revenue PECO ROE ComEd ROE O&M Expense Nuclear Fuel Medium • PECO rate making expectation is ~9-11.5% ROE for 2011 • Achieving expected ROE depends on future rate case results High • Generally, hedges are executed on a ratable basis over 3 years. The position is physically well hedged in the prompt year (2009) and significantly open in the outer year (2011). Medium • ComEd expectation is ~9-10% ROE for 2011 • Achieving expected ROE depends on future rate case results Low-Medium • Company-wide cost savings initiative • Inflationary pressures and rising pension & post- retirement costs Low • 100% physically contracted in 2011 with modest contractual price inflators/deflators 2011 Earnings Outlook will be impacted by changes in future commodities and forward power prices |
 18 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 2001 2002 2003 2004 2005 2006 2007 2008 2009E $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 Cash flow from operations Annual cash dividend / share Stable Cash Flows and Commitment to Value Return (1) Cash Flows from Operations primarily include net cash flows provided by operating
activities, excluding counterparty collateral activity, and including net cash flows used in investing activities other than capital expenditures. Cash Flows from
Operations in 2005 reflect discretionary aggregate pension contributions of $2 billion. (2) Dividend Yield was calculated as (Annual Dividend Paid / Average Daily Closing Share Price) Exelon produces strong and consistent cash flows and continues to honor its commitment
to return value to shareholders Strong and consistent cash flows from operations (1) Over 12% compound annual dividend growth rate since 2001 Sustainable Value Dividend Yield 1.58%
1.76% 1.68% 2.66% 3.24% 2.77%
2.40% 2.75% 3.91% (2) |
 19 Value Return Framework Less Equals Maintenance Capital and Committed Dividends Free Cash Flow before Dividends and CapEx Strengthen Balance Sheet / Increase Financial Flexibility Invest in Growth Available Cash and Balance Sheet Capacity (1) Return Value via Share Repurchases, Dividends Monetize We evaluate value return on an annual basis (1) Exelon on a standalone basis targets a FFO/Debt Ratio of 20-30%.
|
 20 Implementing Exelon’s Low-Carbon Strategy • Voluntary commitment: 8% reduction in GHG by YE2008 (from 2001) – Achieved greater than 30% reduction • Initiatives included: – Closed older, inefficient fossil-fueled power plants; – Incorporated emissions and their potential cost into its business analyses; – Reduced leakage of SF6 and methane; – Increased use of renewable energy; and – Internal energy efficiency initiatives • Validating goal achievement with EPA in Q1 2009 EPA Climate Leaders (2001 – 2008) • Reduce, offset or displace >15 million metric tons of GHG emissions (M MT CO2e) per year by 2020 – Reduce or offset Exelon’s carbon footprint (Potential: ~5M MT C02e)
– Help our customers/communities reduce their emissions (Potential: >3.5M MT
C02e) – Offer more low-carbon electricity in the marketplace (Potential: up to 12.5M MT C02e) Exelon 2020: A Low Carbon Roadmap (2008 – 2020) |
 21 Increased our portfolio of PPAs for renewable generation by over 200 MW in 2008 Advancing nuclear power uprate projects totaling 350 MW by 2013 Exelon 2020 Update Offer more low carbon electricity in the marketplace Help our customers and the communities we serve reduce their GHG emissions Reduce or offset our footprint by greening our operations Reduce, offset or displace more than 15 million metric tons of GHG emissions per year by 2020 Implemented improvements that reduce building energy consumption 11% toward our 25% goal Increased utilization of hybrid vehicles and introduced new vehicle guidelines to
enhance fuel efficiency and reduce emissions Launched comprehensive program to green the supply chain, including Carbon Disclosure
Project Supply Chain survey and Electric Utility Industry Sustainable
Supply Chain Alliance Recycled/reused >30 million pounds of scrap metal,
meters and transformers, along with >0.7 million gallons of oil in
2008 Introduced portfolio of department and employee initiatives Introduced suite of new energy efficiency programs ComEd Smart Ideas: Programs for residential and commercial customers which will
save in excess of 166,000 MWhs in the first year PECO: Planning underway to reduce consumption by 3% and peak load by 4.5% by 2013
Investing in smart grid technology and new pricing programs – ComEd is preparing for the 2009 AMI pilot launch for 100,000 customers Expanding green products, e.g. Green-e certified renewable energy credits (RECs),
Emission Free Energy Certificates Conducting comprehensive customer education and outreach around energy efficiency
3 2 1 |
 22 Recognized Environmental Leadership • Named for the third consecutive year to the Dow Jones Sustainability Index - North America • Named to Carbon Disclosure Leadership Index of the Carbon Disclosure Project for the fourth consecutive year • Named an Electric Sector Sustainability Leader, Silver Class in PwC/SAM’s “The Sustainability Yearbook 2008” • Signatory to the Ceres/Investor Network on Climate Risk and the Global Roundtable on Climate Change statements • Member of the United States Climate Action Partnership (USCAP), Pew Center on Global Climate Change’s Business Environmental Leadership Council, and Ceres • Environmental Management Systems (EMS) at over 80% of Exelon’s operating sites/organizations are ISO 14001 certified • Three Exelon facilities have obtained Leadership in Energy and Environmental
Design (LEED ® ) certification by the U.S. Green Building Council; other facilities are pursuing certification |
 23 Exelon’s Strategic Direction • Deliver superior operating performance – Assure safety at all times – Keep the lights on – Maintain nuclear excellence – Enhance environmental performance • Advance competitive markets – Support the continued improvement of competitive wholesale markets – Provide reliable, affordable, low-carbon products to customers – Build economic new generation • Exercise financial discipline and maintain financial flexibility – Maintain adequate liquidity and ensure investment grade credit rating – Hedge market risk appropriately – Focus on value, deploy our capital wisely • Build healthy, self-sustaining delivery companies – Pursue fair regulatory treatment and improved financial health for ComEd – Manage PECO’s 2011 transition to market • Drive the organization to the next level of performance – Continuously improve productivity – Insist on accountability for results and values – Foster positive employee relations – Identify, develop and retain key and diverse talent • Adapt and advance Exelon 2020 – Reduce or offset our carbon footprint – Help our customers reduce their GHG emissions – Offer more low-carbon electricity • Rigorously evaluate and pursue growth opportunities and advancements in clean technology – Aggressively pursue ‘smart grid’ opportunities – Capture value from emerging renewable technologies • Build the premier, enduring competitive generation company – Increase our scope and scale to succeed throughout industry cycles – Adapt the generation portfolio to a changing marketplace + Protect Today’s Value Grow Long-Term Value |
 24 |
  25 Exelon Generation 2009 EPS Contribution Generation’s 2009 earnings holding up well despite difficult economic
environment (1) Estimated contribution to Exelon’s operating earnings guidance. (2) Primarily reflects uranium settlements and option gains reported in 2Q08. ($0.20) ($0.05) $0.09 RNF O&M Other Depreciation ($0.05) $ / Share Key Items: Pension &
OPEB ($0.09) Inflation
($0.07) Cost Efficiency Initiative $0.06 Nuclear Outages $0.04 2008A 2009E (1) $3.10 – $3.35 $3.46 Key Items: Discrete 2008 Gains (2) ($0.16) Nuclear Fuel Expense ($0.08) Market/Portfolio Position/Generation $0.04 |
 26 Exelon Generation • Large, low-cost, low-emissions, exceptionally well-run nuclear fleet • Complementary and flexible fossil and hydro fleet • Potential Carbon legislation • Well positioned to capture improving power market fundamentals • End of below-market contract in Pennsylvania beginning 2011 Value Proposition • Continue to focus on operating excellence, cost management, and market discipline • Support competitive markets • Execute on power and fuel hedging programs • Pursue nuclear & hydro plant relicensing and strategic investment in material condition • Maintain industry-leading talent Protect Value • Pursue potential for nuclear plant uprates • 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 |
 27 Basics of Business Unchanged $10.00 $12.00 $14.00 $16.00 $18.00 $20.00 2003 2004 2005 2006 2007 2008 Exelon Industry Industry leader in Production Cost Nuclear Annual Average Production Cost ($/MWhr) Petroleum Gas Coal Nuclear U.S. Electricity Production Costs (2000-2007) (1) (1) In 2007 Cents/kWh. Source Global Energy Decisions May 2008; Production
Costs = Operations and Maintenance + Fuel Costs 10.26 6.78 2.47 1.76 0.0 2.0 4.0 6.0 8.0 10.0 12.0 2003 2004 2005 2006 2007 |
 28 Lowest Cost Nuclear Fleet Operator Among major nuclear plant fleet operators, Exelon is consistently the lowest-cost
producer of electricity in the nation 1 Quartile 2 Quartile 3 Quartile 4 Quartile 2006-2007 Average Production Cost for Major Nuclear Operators (1) Average (1) Source: 2007 Electric Utility Cost Group (EUCG) survey. Includes Fuel Cost plus Direct O&M divided by net generation. st nd rd th |
 29 Effectively Managing Nuclear Fuel Costs Components of Fuel Expense in 2008 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. 2008 – 2011: 100% hedged in volume 2012: ~80% hedged in volume 2013: ~70% hedged in volume All charts exclude Salem 0.0 2.0 4.0 6.0 8.0 10.0 2008 2009 2010 2011 2012 2013 Enrichment 38% Fabrication 17% Nuclear Waste Fund 22% Tax/Interest 1% Conversion 3% Uranium 19% 0 200 400 600 800 1,000 1,200 1,400 2008 2009 2010 2011 2012 2013 Nuclear Fuel Expense (Amortization + Spent Fuel) Nuclear Fuel Capex 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2008 2009 2010 2011 2012 2013 Exelon Average Reload Price Projected Market Price (Spot) |
 30 Uranium Price Volatility Long-term Uranium Price Trend Long-term equilibrium price expected to be $40-$60/lb Eighteen-Month 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) 0 20 40 60 80 100 120 140 160 0 20 40 60 80 100 120 140 |
 31 World-Class Nuclear Operator Average Capacity Factor 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) Range 5-Year Average Range of Fleet 2-Yr Avg Capacity Factor (2003-2007) EXC 93.5% Sustained production excellence 80% 85% 90% 95% 100% Exelon Industry |
 32 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 7 8 9 10 11 12 13 Note: Data includes Salem. Net nuclear generation data based on ownership interest
• 18 or 24 months • Duration: ~24 days Nuclear Refueling Cycle • Reflects extended steam generator replacement outage • Based on the refueling cycle, we will conduct 10 refueling outages in 2009, versus 12 in 2008 2009 Refueling Outage Impact Refueling Outage Duration Nuclear Output Actual Target • 2008 reflects Salem’s extended steam generator replacement outage • 2008 average outage duration is 24 days without Salem 2008 Refueling Outage Impact 0 10 20 30 40 50 60 2004 2005 2006 2007 2008 Exelon w/ Salem Industry w/o Exelon |
 33 Total Portfolio Characteristics 106,385 99,800 23,686 18,900 13,900 40,900 40,966 5,137 0 50,000 100,000 150,000 200,000 2008A 2009E ComEd Swap IL Auction PECO Load Actual Forward Hedges & Open Position Expected Total Supply (GWh) Expected Total Sales (GWh) 91,595 91,600 47,747 47,300 30,300 29,449 7,383 4,300 0 50,000 100,000 150,000 200,000 2008A 2009E Forward / Spot Purchases Fossil & Hydro Mid-Atlantic Nuclear Midwest Nuclear 176,174 176,174 173,500 173,500 (1) (1) Includes supply from fossil and hydroelectric generation under Exelon Generation’s long-term power purchase agreements (PPAs). |
 34 Hedging Targets (1) Percent financially hedged is our estimate of the gross margin that is hedged at a 95%
confidence level given the current assessment of market volatility. The formula is the gross margin at the 5 percentile / expected gross margin. Power Team utilizes various products and channels to market in order to optimize Exelon Generation’s earnings: • Block product sales in power • Options in power and natural gas • Full requirements sales via retail channel and wholesale load procurement processes • Supplement the portfolio with structured transactions • Use physical and financial fuel products to manage variability in fossil generation output Target Ranges 90% - 98% 70% - 90% 60% - 80% >90% Current Position ~90% Near top end of range Prompt Year (2009) Second Year (2010) Third Year (2011) Financial Hedging Range (1) Flexibility in our targeted financial hedge ranges allows us to be opportunistic while
mitigating downside risk Financial hedge ratios reflect a range of revenue net fuel based on observed market prices and volatility • Generally, hedges are executed on a ratable basis over a three-year window; therefore, the position is well hedged in the prompt year and significantly open in the outer years • Utilize options to hedge risk and preserve upside How to Calculate a Financial Hedge Ratio: Gross Margin @ the 5 percentile Financial Expected Gross
Margin Hedge Ratio = th th |
 35 Exelon Generation Has Limited Counterparty Exposure Net Exposure After Credit Collateral (1) (in millions) Investment grade $1,113 Non-investment grade 3 No external ratings 27 Total $1,143 (1) As of December 31, 2008. Does not include credit risk exposure from uranium
procurement contracts or exposure through Regional Transmission Organizations, Independent System Operators and New York Mercantile Exchange and Intercontinental
Exchange commodity exchanges. Additionally, does not include receivables related to the supplier forward agreements with ComEd and the PPA with
PECO. Exelon Generation transacts with a diverse group of
counterparties, predominantly all investment grade, and has ample liquidity
to support its operations Exelon Generation – Sufficient Liquidity Aggregate credit facility commitments of $4.8 billion that largely extend through 2012 – $4.7 billion available as of February 27, 2009 Strong balance sheet – A3/BBB/BBB+ Senior Unsecured Rating Net Exposure by Type of Counterparty (1) Coal Producers 1% Financial Institutions 34% Investor-Owned Utilities, Marketers, and Power Producers 62% Other 3% |
 36 Long-Term Natural Gas Price Forecasts Remain High Reserve Margins Declining Market Dynamics Carbon Credit ($/Tonne) Carbon Legislation Progressing 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 5 10 15 20 25 30 35 40 45 0 5 10 15 20 25 30 PJM-East ERCOT NI-Hub PJM West (1) As of 2/13/2009 Europe Carbon-Trading 2012: $11-13/tonne Bingaman-Specter 2012: $12/tonne EIA Carbon Case 2010: $31/tonne Lieberman-Warner Possible $20 to $40/tonne -15% -10% -5% 0% 5% 10% 15% 20% 25% 30% 2008 2009 2010 2011 2012 2013 NYMEX (1) $3 $4 $5 $6 $7 $8 $9 $10 $11 2008 2010 2012 2014 2016 2018 2020 Various 3 rd party estimates |
 37 Long-Term Investment Thesis Power Market Fundamentals Reserve Margins Capacity Prices Construction Costs Demand Trends Demand Profile Changes Off-Peak Usage Commodities Natural Gas Coal Environmental Position Carbon SO2, NOX Mercury Exelon Generation’s long-term value is driven by having well-run nuclear
assets located in competitive markets, supported by positive market
dynamics Lowest-cost, low-emissions nuclear fleet |
 38 Exelon Energy • Provides another channel to market to execute Power Team’s hedging strategy • Exelon Energy aggregate load profile complements generation portfolio • Provides long-term sales to creditworthy customers, reducing price and earnings risk • Vehicle for Exelon Generation to advocate for competitive markets • Provides customer benefits from competitively priced energy offerings • Direct access to customers • Provides market intelligence: trends in demand, expectations for product and services • Channel to offer products that support Exelon 2020 Plan and demand reduction related programs • Renewable Energy Credit (REC) sales • Low Carbon Energy (Generation Attribute Tracking System (GATS) tracking and transfer of nuclear energy attributes) • Demand Side Management Programs • Growth vehicle in target regions as Exelon Generation footprint expands • Planned expansion into Pennsylvania market will provide another channel to market when PECO purchase power agreement (PPA) ends in 2011 Exelon Energy supplies a wide range of energy and natural gas products directly to
industrial and commercial customers in Illinois, Michigan and Ohio. Exelon
Energy leverages broad experience in wholesale markets, providing a key element to executing Exelon’s Strategic Direction. Exelon Energy |
 39 Reliability Pricing Model Auction PJM RPM Auction ($/MW-day) (1) All 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) EMAAC obligation consists of load obligations from PECO and BGS. The PPL obligation begins January 2010 and ends December 2010. (4) Removing State Line from the supply in October 2007 reduces this by 515 MW. (5) 08/09 Capacity supply decreased due to roll-off of several PPAs. (6) In 09/10, obligation is reduced due to roll-off of part of ComEd auction load
obligation in May 2009. (7) MAAC = Mid-Atlantic Area Council; APS = Allegheny Power System. (8) PECO PPA expires December 2010. 2007 / 2008 2008 / 2009 2009 / 2010 2010 / 2011 2011/2012 in MW Capacity (2) Obligation Capacity (2) Obligation Capacity (2) Obligation Capacity (2) Obligation Capacity (2) Obligation RTO 16,000 (4) 6,600- 6,800 14,500 (5) 6,600- 6,800 12,700 4,750- 4,950 (6) 12,700 0 23,200 0 Eastern MAAC 9,500 9,500- 9,800 (3) 9,500 9,550- 9,850 (3) 9,500 9,750- 9,950 (3) MAAC + APS (7) 1,500 0 MAAC 11,000 9,300- 9,500 (3)(8) Exelon Generation Participation within PJM Reliability Pricing Model (1) 40.80 197.67 148.80 111.92 191.32 191.32 102.04 174.29 174.29 110.00 RTO Eastern MAAC MAAC + APS MAAC 2007/2008 2008/2009 2009/2010 2010/2011 2011/2012 |
 40 $0 $20 $40 $60 $80 $100 $120 2008 Auction 2009 Auction Full Requirements Cost ATC Forward Energy Price NJ BGS Auction Results (2008 – 2009) $111.50/MWh (36 month price) $103.72/MWh (36 month price) ~$42 ~$48 $69.50 -$71 $55.50 -$57.25 • The results shown are for PSE&G • “ATC Forward Energy Price” represents the range of forward market prices that traded during the 2008 and 2009 Auctions Full Requirements Costs Auction Results Load Shape & Ancillary Services $10.00 Capacity $16.00 Transmission & Congestion $16.00 Renewable Energy $3.00 Migration & Volumetric Risk & Other $3.00 Note: BGS = Basic Generation Service |
 41 Current Market Prices 8.28 6.32 6.98 43.87 13.04 66.38 (4) 6.74 (4) 60.87 (3) 59.68 (2) 41.42 (2) 51.07 (2) 2006 (1) 7.80 6.65 7.68 47.54 9.67 69.72 (4) 6.74 (4) 59.44 (3) 66.72 (2) 45.47 (2) 59.76 (2) 2007 (1) 7.42 5.57 6.97 105.36 12.17 104.97 (4) 8.85 (4) 73.36 (3) 80.56 (2) 49.00 (2) 68.52 (2) 2008 (1) 7.44 6.70 8.15 61.80 10.66 46.39 4.71 38.56 48.98 30.63 45.08 2009 (5) 7.46 5.30 7.23 65.51 12.45 55.79 6.08 51.03 56.69 31.64 50.35 2010 (6) 7.65 5.63 7.12 67.51 13.71 60.63 6.69 57.52 61.58 36.93 54.18 2011 (6) Units 2012 (6) PRICES (as of February 27, 2009) PJM West Hub ATC ($/MWh) 56.40 PJM NiHub ATC ($/MWh) 41.51 NEPOOL MASS Hub ATC ($/MWh) 63.56 ERCOT North On-Peak ($/MWh) 60.13 Henry Hub Natural Gas ($/MMBTU) 6.88 WTI Crude Oil ($/bbl) 64.12 PRB 8800 ($/Ton) 14.60 NAPP 3.0 ($/Ton) 67.50 ATC HEAT RATES (as of February 27, 2009) PJM West Hub / Tetco M3 (MMBTU/MWh) 7.22 PJM NiHub / Chicago City Gate (MMBTU/MWh) 6.15 ERCOT North / Houston Ship Channel (MMBTU/MWh) 7.68 (1) 2006, 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 February 27, 2009
and market prices for the balance of the year. (6) 2010, 2011 and 2012 are forward market prices as of February 27, 2009.
|
 42 Market Price Snapshot 20 30 40 50 60 70 80 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 35 45 55 65 75 85 95 105 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 50 60 70 80 90 100 110 120 130 140 150 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 5.5 6.5 7.5 8.5 9.5 10.5 11.5 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 Forward NYMEX Natural Gas PJM-West and Ni-Hub On-Peak Forward Prices PJM-West and Ni-Hub Wrap Forward Prices 2010 2011 Rolling 12 months, as of February 27, 2009. Source: OTC quotes and electronic trading
system. Quotes are daily. Forward NYMEX Coal $6.08 $6.69 2010 2011 $57.75 $62.25 2010 Ni-Hub 2011 Ni-Hub 2011 PJM-West 2010 PJM-West 2010 Ni-Hub 2011 Ni-Hub 2011 PJM-West 2010 PJM-West $58.28 $63.04 $39.75 $29.25 $46.46 $24.52 $45.75 $43.39 |
 43 Market Price Snapshot 7 8 9 10 11 12 13 14 15 16 17 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 8 8.2 8.4 8.6 8.8 9 9.2 9.4 9.6 9.8 10 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 50 55 60 65 70 75 80 85 90 95 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 5.5 6.5 7.5 8.5 9.5 10.5 11.5 2/08 3/08 4/08 5/08 6/08 7/08 8/08 9/08 10/08 11/08 12/08 1/09 2/09 2011 2010 2010 2011 2010 2011 Houston Ship Channel Natural Gas Forward Prices ERCOT North On-Peak Forward Prices ERCOT North On-Peak v. Houston Ship Channel Implied Heat Rate 2010 2011 ERCOT North On Peak Spark Spread Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder $5.69 $6.32 $57.52 $51.03 $8.97 $9.11 $7.47 $9.46 Rolling 12 months, as of February 27, 2009. Source: OTC quotes and electronic trading
system. Quotes are daily. |
 44 Exelon Nuclear Fleet Overview Fleet also includes 4 shutdown units: Peach Bottom 1, Dresden 1, Zion 1 &
2. (1) Capacity based on ownership interest. Average in-service time = 28 years 2011 42.59% Exelon, 57.41% PSEG 2016, 2020 503, 491 (1) W PWR 2 Salem, NJ Life of plant capacity 100% 2014; renewal filed 2008 837 B&W PWR 1 TMI-1, PA Dry cask 100% 2009; renewal filed 2005 625 GE BWR 1 Oyster Creek, NJ Dry cask 50% Exelon, 50% PSEG Renewed: 2033, 2034 570, 570 (1) GE BWR 2 Peach Bottom, PA Dry cask 75% Exelon, 25% Mid- American Holdings Renewed: 2032 650, 653 (1) 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 1149, 1146 GE BWR 2 Limerick, PA 2018 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 Expiration / Status Net Annual Mean Rating MW 2008 Plant, Location |
 45 |
 46 ComEd 2009 EPS Contribution (1) Estimated contribution to Exelon’s operating earnings guidance. (2) Disallowances recorded in September 2008 in connection with the Illinois Commerce
Commission (ICC) order in ComEd’s distribution rate case. ComEd’s
operating earnings are expected to increase in 2009 primarily due to continued execution of its Regulatory Recovery Plan 2008A RNF O&M Depreciation / Amortization Interest Expense $0.45 - $0.55 $0.33 $0.20 $0.01 ($0.04) 2009E (1) Key Items: Cost Efficiency Initiative $0.08 Rate Case Disallowance (2) $0.02 Storms $0.02 Energy Efficiency ($0.04) Pension & OPEB ($0.04) Inflation ($0.03) $ / Share Key Items: Distribution Rates
$0.17 Energy
Efficiency $0.04 Weather
$0.01 Load Growth ($0.02) ($0.00) $0.03 Other |
 47 ComEd Load Growth Trends Weather-Normalized Load Growth ComEd Customer Usage by Revenue Class Key Economic Indicators Top 380 Customer Usage by Segment Other 2% Residential 31% Small C&I 36% 380 Large C&I 18% Other Large C&I 13% 3% Leisure & Hospitality 9% Trade, Transportation & Utilities 11% Finance, Professional & Business Services 12% Health & Educational Services 13% Government 52% Manufacturing Chicago U.S. Unemployment rate (1) 7.1% 7.6% 4 Qtr ‘08 annualized growth in gross domestic/metro product (2) (7.0%) (6.2%) 12/08 Home price index (3) (14.3%) (18.5%) (1) Source: Illinois Dept. of Employment Security (Dec08) and U.S. Dept. of Labor
(Jan09) (2) Source: Moody’s Economy.com (3) Source: S&P Case-Shiller Index Q4 2008 FY 2008 2009E Customer Growth 0.1% 0.5% 0.2% Average Use-Per-Customer (0.6%) 0.0% (0.8%) Total Residential (0.5%) 0.5% (0.6%) Small C&I (2.9%) (0.3%) (0.8%) Large C&I (1.0%) (0.4%) (2.1%) All Customer Classes (1.6%) (0.1%) (1.1%) Note: C&I = Commercial & Industrial th |
 48 6.1 2.0 6.9 6.4 2.0 2.1 Transmission Distribution ComEd – Moving Forward Executing Regulatory Recovery Plan ~9 – 10% ~ 45% ~7.3 – 8.8% ~ 46% ROE Equity (1) ~5.0 – 6.0% ~ 45% 8.1 8.4 9.0 2008 2009E 2011 (Illustrative) (2) Average Annual Rate Base (1) ($ in Billions) ComEd’s earnings are expected to increase as regulatory lag is reduced over time through regular rate requests, putting ComEd on a path toward appropriate returns
(1) Equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill). Projected book equity ratio in 2008 is 58%. (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. • Cost reduction and control initiatives combined with the recent delivery service tariff (DST) rate increase and regular transmission rate updates • Illinois Power Agency proposed procurement plan for ComEd - first procurement in Spring 2009 • Actively promoting/implementing efficiency, renewable energy, and demand-side management programs • Studying future test year approach for distribution rate filing |
 49 Illinois Power Agency Procurement Plan • On January 7, 2009 the Illinois Commerce Commission’s Final Order was entered (1) which approved, with minor modifications, the Illinois Power Agency’s proposed procurement plan originally filed in September 2008. • In April/May 2009 a single procurement event will be conducted to procure the remaining ComEd 2009-10 load (~29% of the total ComEd load). Auction Contracts Financial Swap 3/08 RFP Jun 2007 Jun 2008 Jun 2009 Jun 2010 Jun 2011 Jun 2012 Jun 2013 NOTE: For illustrative purposes only. Assumes constant load profile each year. 2009 2009 Future Procurement by Illinois Power Agency 2010 2010 2011 2012 2011 (1) Reference: ICC Docket # 08-0519 Auction Contracts Financial Swap 3/08 RFP Jun 2007 Jun 2008 Jun 2009 Jun 2010 Jun 2011 Jun 2012 Jun 2013 NOTE: For illustrative purposes only. Assumes constant load profile each year. 2009 2009 Future Procurement by Illinois Power Agency 2010 2010 2011 2012 2011 |
 50 The ICC issued a final Order in ComEd’s distribution rate case – granting a revenue increase of $273.6 million that took effect on September 16, 2008: (14) 345 359 Depreciation and Amortization $(87) 274 361 Total Revenue Increase 3 129 132 Other Revenues (11) 987 998 O&M Expenses (22) 10.30% ROE / 45.04% Equity 10.75% ROE / 45.11% Equity ROE / Cap Structure $(43) $6,694 $7,071 Rate Base Impact on Revenue Increase ICC Order ComEd Original Request ($ in millions) ComEd Executing on Regulatory Recovery Plan – 2008 Rate Case |
 51 |
  52 PECO 2009 EPS Contribution (1) Excludes preferred dividends (2) Estimated Operating Earnings PECO’s 2009 operating earnings are expected to be comparable to 2008 due to
the gas distribution rate increase and lower bad debt expense, offset by higher
CTC amortization $/Share RNF $0.45-$0.55 (1) $0.49 (1) $0.05 ($0.10) Depreciation/ Amortization 2008A 2009E (2) Key Items: Gas Rate Case $0.07 Weather
0.03 Load
Growth (0.02) Pricing/Cust. Mix (0.02) Other
(0.01) Key Items: Bad Debt $0.07 Cost Efficiency 0.02 Inflation/Other (0.06) Regulatory/Post 2010 (0.01) Pension & OPEB (0.01) $0.01 O&M $0.04 Interest Expense/ Other Key Items: Competitive Transition Charge (CTC) Amortization ($0.09) Key Items: CTC Interest Expense/ Other
$0.04 |
 53 PECO Load Growth Trends Other 2% Other Large C&I 21% 150 Large C&I 21% Small C&I 22% Residential 34% Weather-Normalized Electric Load Growth Q4 2008 FY 2008 2009E Customer Growth 0.5% 0.7% 0.1% Average Use-Per-Customer (0.9%) 1.1% (0.6%) Total Residential (0.4%) 1.8% (0.5%) Small C&I 0.7% (0.2%) (0.8%) Large C&I (2.4%) 0.1% (1.9%) All Customer Classes (1.1%) 0.6% (1.1%) PECO Customer Usage by Revenue Class Philadelphia U.S. 1/09 Unemployment rate (1) 6.8% 7.6% 4 th Qtr ‘08 annualized growth in gross domestic/metro product (2) (4.0%) (6.2%) Key Economic Indicators Top 150 Customer Usage by Segment 18% Health & Educational Services 19% Manufacturing 21% Petroleum 3% Retail Trade 4% Other 9% Transportation, Communication & Utilities 13% Finance, Insurance & Real Estate 13% Pharmaceuticals (1) Source: Moody’s Economy.com and U.S. Department of Labor (2) Source: Moody’s Economy.com |
 54 2.8 2.9 3.2 0.5 0.6 1.7 0.9 1.1 1.1 1.2 0.7 Gas CTC Electric Transmission Electric Distribution PECO – Moving Forward Actively Engaged in Transition ~9 – 11.5% (3) Not applicable due to transition rate structure Rate Making ROE Equity ~50 – 53% 6.1 5.5 5.1 Average Annual Rate Base (1) ($ in Billions) 2008 2009E 2011 (Illustrative) (2) (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. (3) Assumes PECO is awarded 100% of potential requested revenue increases for rate cases
filed during the planning period. • Successful outcome of 2008 gas rate case provides for increased gas revenues of $76.5 million • Next rate case(s) expected to be filed in 2010 – 2011 • Developing plans and programs to implement energy efficiency, demand response and smart meter provisions of Act 129 (HB2200) • Transitioning through an orderly structure to market-based rates – Working with the Governor, Legislature and Pennsylvania Public Utility Commission (PAPUC) for post-transition rates and structure – Power Procurement Plan filed 9/10/08 to address post-transition plan beginning in 2011 along with mitigation alternatives Pursuing a successful transition to market-based rates and regular rate case
outcomes |
 55 2.63 2.63 0.48 0.48 2.41 6.00 10.75 PECO Average Electric Rates (1) System Average Rates based upon Restructuring Settlement Rate Caps on Energy and
Capacity increased from original settlement by 1.6% to reflect the
roll-in of increased Gross Receipts Tax and $0.02/kWh for Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustment. System Average Rates also adjusted for sales mix based on current
sales forecast. Assumes continuation of current Transmission and
Distribution Rates. (2) Provided for illustration only. Not necessarily representative of PECO’s
internal forecast, which is highly dependent at any point in time on energy
market conditions. 2011 2008 – 2010 Energy / Capacity Competitive Transition Charge (CTC) Transmission Distribution 11.52¢ (1) Unit Rates (¢/kWh) Electric Restructuring Settlement ~20% 13.86¢ Assumptions Illustrative Rate Increase Based on Average PPL Procurement Results (2) • 2011 default service rate will reflect associated full requirements costs and be acquired through multiple procurements • Using the average results of completed PPL procurements for 2010 and assuming a 50/50 weighting of Residential and Small C&I customers produces a proxy of 10.75¢/kWh. This will result in a system average rate increase of ~20% • PECO’s 2011 full requirements price expected to differ from PPL due, in part, to the timing of the procurement (2011 vs. 2010) and locational differences • Rates will vary by customer class and may be impacted by legislation and procurement model Residential Small C&I Round 1, 7/2007 $101.77 $105.11 Round 2, 10/2007 $105.08 $105.75 Round 3, 3/2008 $108.80 $108.76 Average PPL Procurement Results Round 4, 10/2008 $112.51 $111.94 $107.04 $107.89 |
 56 PECO’s procurement plan for obtaining default service Post 2010 includes a portfolio of full requirements and spot products competitively procured through multiple RFP solicitations Mitigation plan includes early staggered procurement, voluntary post-rate cap phase-in, gradual phase-out of declining block rate design, customer education, enhanced retail choice program, and low-income rate design changes Block Products & Spot Long-Term contracts No intervener challenge on one-way margining Default Service Procurement and Mitigation Filing Early Phase-in Filing Addressing Key Intervener Issues Early phase-in proposal provides a voluntary opt-in program for customers to pre-pay towards 2011 prices PAPUC approval expected in March 2009 to allow for implementation July 1, 2009 PECO’s third quarter 2008 regulatory filings address procurement and rate
mitigation – allowing PECO to execute on its regulatory strategy
PECO Post-2010 Procurement Plan |
 57 Pennsylvania Act 129 Highlights • Energy Efficiency (EE) and Demand Response (DR) – EE Targets of 1% reduction in consumption by 2011, 3% reduction by 2013 – DR target of 4.5% reduction in peak demand by 2013 – Up to $20 million in penalties for failure to achieve targets – Full and current program cost recovery through surcharge mechanism – Reduced consumption reflected in future rate base proceedings – Spending cap equal to 2% of revenue • Smart Meters – Utilities must file smart meter file plan with PAPUC by August 2009 – Required to furnish meters upon 1) customer request, 2) for new construction,
and 3) on a depreciation schedule not to exceed 15 years – Base rate or surcharge recovery • Procurement – Competitive procurement using auctions, RFPs or bilateral agreements – Prudent mix of spot, short term or long term (defined as 4-20 years) contracts
PECO will file Energy Efficiency and Demand-Side Management plan in
2009 |
 58 Federal Policy Update |
 59 Advocating for Coherent Public Policies Actively involved in the climate debate in Washington, D.C. Lobbying in favor of enacting legislation that is national, mandatory and economy-wide Favor a cap-and-trade system over a carbon tax Believe that allowances should be provided to local distribution companies for the benefit of their customers, including rate impact mitigation To limit economic impacts, support a cost containment mechanism that supports a market price for carbon that increases over time Federal, mandatory, economy-wide cap & trade climate legislation Support for energy efficiency and conservation across the entire economy, including new standards as well as programs and investment by utilities An economically responsible approach to renewable energy Financial support for new low-carbon, base load generation, such as clean coal and next- generation nuclear Continued commitment to competitive electricity markets to spur investment and innovation in new low-carbon solutions Advocating for Federal Climate Change Legislation |
 60 Status of Legislative Initiatives – Cap and Trade program to reduce emissions by 80% by 2050 with 100% auction of
allowance permits – Proposed long-term budget plans assume ~$70B of annual carbon revenues beginning in 2012 – Renewable Electricity Standard (RES): 10% by 2012 and 25% by 2025 Congress: Senate: • Climate: Chairman Boxer released principles for climate change legislation • Majority Leader Reid has indicated his hope for a bill in late summer • Renewable Electricity Standard: Chairman Bingaman introduced 20% RES by 2021 House: • Climate: Chairman Waxman pledges to have a bill out of the Energy and Commerce
Committee by Memorial Day • Renewable Electricity Standard: Chairman Markey introduced 25% RES by 2025 Obama Administration Climate and Energy Plan: |
 61 Stimulus Package Impact On Energy Industry • Long-term extension of production tax credit (PTC) • Temporary election to claim investment tax credit in lieu of PTC • Grants in lieu of tax credits for renewables • Provides loan guarantees for renewable and transmission projects • Provides $2.5 billion for renewable and energy efficiency research, development, demonstration and deployment (RDD&D) Renewables Energy Efficiency Smart Grid • Provides $3.1 billion for State Energy Programs • Provides $3.2 billion for Energy Efficiency and Conservation Block Grants to the States • Provides $5 billion for weatherization • Provides $4.5 billion for the Smart Grid Investment Program • Authorizes Federal match for up to 50 percent of project costs Actively working with local officials to discuss coordination opportunities |
 62 Federal Environmental Regulatory Update Clean Air Interstate Rule (CAIR) Clean Air Mercury Rule (CAMR) Greenhouse Gas (GHG) Emissions In a December 2008 decision, the D.C. Circuit Court of Appeals allowed CAIR to
remain in effect in eastern states pending U.S. EPA revisions to address issues raised by the court in its original July 11, 2008 opinion. CAIR NOx reductions begin in 2009 (ozone-season and, for the first time, annual). Annual NOx imposes
new costs in non-ozone season months. CAIR SO2 reductions start in
2010. Rule vacated by D.C. Circuit Court of Appeals in February 2008. EPA appeal to Supreme Court withdrawn in January 2009. EPA now expected to propose new
hazardous air pollutant (HAP) rulemaking for electric generating units that may include other HAPs in addition to mercury from coal-fired generation. In response to Massachusetts vs. U.S. EPA, EPA is required to consider whether
GHG emissions may reasonably be anticipated to endanger public health or
welfare. Should it issue an affirmative finding, EPA could elect to
pursue regulation of GHG emissions under the existing federal Clean Air Act. An advanced notice of proposed rulemaking (ANPR) was issued last year. EPA
currently reviewing ANPR comments. Federal legislation is the preferred
option. Significant short-term environmental regulatory uncertainty
remains due to litigation results and change of administration.
However, long-term trend remains towards tighter air quality
regulations that will benefit lower-emission generation |
 63 Key Assumptions, Projected 2009 Credit Measures & GAAP Reconciliation |
 64 Key Assumptions 37.3 1.2 2.6 23.86 115.37 6.65 6.84 45.47 7.68 7.78 59.76 6.74 148,307 41,343 189,650 94.5 2007 Actual 36.1 (0.1) 0.6 82.39 169.09 5.57 8.79 49.00 6.97 9.83 68.52 8.85 135,208 40,966 176,174 93.9 2008 Actual 5.00 Chicago City Gate Gas Price ($/mmBtu) 5.91 Tetco M3 Gas Price ($/mmBtu) 36.7 Effective Tax Rate (%) (4) (1.1) ComEd (1.1) PECO Electric Delivery Growth (%) (3) 106.13 PJM West Capacity Price ($/MW-day) 173.73 PJM East Capacity Price ($/MW-day) 6.96 NI Hub Implied ATC Heat Rate (mmbtu/MWh) 34.79 NI Hub ATC Price ($/MWh) 8.15 PJM West Hub Implied ATC Heat Rate (mmbtu/MWh) 48.18 PJM West Hub ATC Price ($/MWh) 4.98 Henry Hub Gas Price ($/mmBtu) 132,600 Total Genco Market and Retail Sales (GWhs) (2) 40,900 Total Genco Sales to PECO (GWhs) 173,500 Total Genco Sales Excluding Trading (GWhs) 93.1 Nuclear Capacity Factor (%) (1) 2009 Est. (1) Excludes Salem . (2) Includes Illinois Auction sales and ComEd swap. (3) Weather-normalized retail load growth. (4) Excludes results related to investments in synthetic fuel-producing
facilities. Notes: 2007 and 2008 prices are averages for those years. 2009 prices reflect observable prices as of January 31, 2009.
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 65 Projected 2009 Key Credit Measures BBB A- BBB+ BBB- S&P Credit Ratings (3) BBB+ A BBB BBB+ Fitch Credit Ratings (3) A3 A2 Baa2 Baa1 Moody’s Credit Ratings (3) 3.5x 3.6x FFO / Interest ComEd: 17% 13% FFO / Debt 42% 50% Rating Agency Debt Ratio 3.2x 3.0x FFO / Interest PECO: 12% 10% FFO / Debt 49% 54% Rating Agency Debt Ratio 24% 47% Rating Agency Debt Ratio 123% 47% FFO / Debt 28.2x 10.6x FFO / Interest Exelon Generation: 50% 34% 6.9x Without PPA & Pension / OPEB (2) 61% Rating Agency Debt Ratio 23% FFO / Debt 5.6x FFO / Interest Exelon Consolidated: With PPA & Pension / OPEB (1) Notes: Exelon and PECO metrics exclude securitization debt. See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to GAAP. (1) Reflects S&P updated guidelines, which include imputed debt and interest related to
purchased power agreements (PPA), unfunded pension and other postretirement benefits (OPEB) obligations, capital adequacy for energy trading, operating lease obligations,
and other off-balance sheet debt. Debt is imputed for estimated pension and OPEB obligations by operating company. (2) Excludes items listed in note (1) above. (3) Current senior unsecured ratings for Exelon and Exelon Generation and senior secured
ratings for ComEd and PECO as of February 27, 2009. On October 21, 2008, S&P put Exelon, ComEd, PECO and Exelon Generation on CreditWatch with negative implications. On
October 21, 2008, Fitch placed Exelon and Exelon Generation on rating watch negative. On November 12, 2008, Moody’s placed the ratings of Exelon, Exelon Generation and PECO under review for possible downgrade. |
 66 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 Note: Reflects S&P guidelines and company forecast. FFO and Debt related to
non-recourse debt are excluded from the calculations. (1) Uses current year-end adjusted debt balance. (2) 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. |
 67 2008 GAAP Reconciliation (0.02) - - (0.02) - City of Chicago settlement with ComEd (0.02) (0.02) - - - NRG acquisition costs 0.03 0.03 Settlement of tax matter 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 (0.22) - - (0.01) (0.21) 2007 Illinois Electric Rate Settlement 0.41 - - - 0.41 Mark-to-market adjustments from economic hedging activities (0.27) - - - (0.27) Unrealized gains & losses related to nuclear decommissioning trust funds Exelon Other PECO ComEd ExGen 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. 20 - - - 20 Settlement of tax matter at Generation related to Sithe 272 - - - 272 Mark-to-market adjustments from economic hedging activities (145) - - (7) (138) 2007 Illinois Electric Rate Settlement 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 ExGen 2008 GAAP Earnings Reconciliation (in millions) - City of Chicago settlement with ComEd $2,278 2008 GAAP Earnings (Loss) (184) Unrealized gains & losses related to nuclear decommissioning trust funds $2,293 2008 Adjusted (non-GAAP) Operating Earnings (Loss) |
 68 2009 Earnings Outlook • Exelon’s outlook for 2009 adjusted (non-GAAP) operating earnings excludes the earnings impacts of the following: • Mark-to-market adjustments from economic hedging activities • Unrealized gains and losses from nuclear decommissioning trust fund investments
primarily related to the AmerGen nuclear plants • Significant impairments of assets, including goodwill • Changes in decommissioning obligation estimates • Costs associated with the 2007 Illinois electric rate settlement agreement, including ComEd’s previously announced customer rate relief programs • Costs associated with ComEd’s 2007 settlement with the City of Chicago • Certain costs associated with the proposed offer to acquire NRG Energy Inc. • Other unusual items • Significant future changes to GAAP • Both our operating earnings and GAAP earnings guidance are based on the assumption of normal weather |
 69 Exelon Investor Relations Contacts Inquiries concerning this presentation should be directed to: Exelon Investor Relations 10 South Dearborn Street Chicago, Illinois 60603 312-394-2345 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 Marybeth Flater, Manager 312-394-8354 Marybeth.Flater@ExelonCorp.com |