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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
August 6, 2003
(Date of earliest
event reported)
| Name of Registrant; State of | IRS Employer | |||
| Commission File | Incorporation; Address of Principal | Identification | ||
| Number | Executive Offices; and Telephone Number | Number | ||
| 1-16169 |
EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street – 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
23-2990190 | ||
| 1-1839 |
COMMONWEALTH EDISON COMPANY (an Illinois corporation) 10 South Dearborn Street – 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321 |
36-0938600 | ||
| 1-1401 |
PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
23-0970240 | ||
| 333-85496 |
EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348 (610) 765-6900 |
23-3064219 |
| SIGNATURES | ||||||||
| News Release | ||||||||
| Slide Presentations | ||||||||
| Various Handouts | ||||||||
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Item 5. Other Events
On August 6, 2003, Exelon Corporation (Exelon) issued a news release reaffirming 2003 guidance and announcing workforce reductions related to The Exelon Way. The news release is attached as Exhibit 99.1.
Item 9. Regulation FD Disclosure
On August 6, 2003, Exelon held an investor conference in New York City. The slides and handouts used in the presentation are attached as Exhibits 99.2 and 99.3.
Exhibit Index
| Exhibit No. | Description | |
| 99.1 | News Release | |
| 99.2 | Slide Presentations | |
| 99.3 | Various Handouts |
This combined Form 8-K is being filed separately by Exelon, Commonwealth Edison Company (ComEd), PECO Energy Company (PECO) and Exelon Generation Company, LLC (Generation) (Registrants). Information contained herein relating to any individual registrant has been filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant.
Except for the historical information contained herein, certain of the matters discussed in this Report are 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 the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants’ 2002 Annual Report on Form 10-K — ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants’ 2002 Annual Report on Form 10-K — ITEM 8. Financial Statements and Supplementary Data: Exelon — Note 19, ComEd – Note 16, PECO – Note 18 and Generation – Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) 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 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 Report.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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EXELON CORPORATION COMMONWEALTH EDISON COMPANY PECO ENERGY COMPANY EXELON GENERATION COMPANY, LLC |
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/s/ Robert S. Shapard Robert S. Shapard Executive Vice President and Chief Financial Officer Exelon Corporation |
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| August 6, 2003 |
Exhibit 99.1
News Release
| From: | Exelon Corporation | For Immediate Release | ||
| Corporate Communications | ||||
| P.O. Box 805379 | ||||
| Chicago, IL 60680-5379 | ||||
| Contact: | Linda Marsicano | |||
| 312.394.3099 |
Exelon Corporation Reaffirms 2003 Guidance; Targets to Reduce Workforce 10 percent By 2006
CHICAGO (August 6, 2003) — Senior executives with Exelon Corporation met with investors and analysts today in New York City to update the financial community on progress of The Exelon Way, the company’s program aimed to improve cash flow by $300 — $600 million in cash savings annually by focusing on operational excellence, simplifying procedures and standardizing processes.
Exelon reaffirmed its guidance for 2003 of earnings per share at the upper end of a range of $4.80 to $5.00 and provided guidance of between $5.15 and $5.45 per share for 2004.
As part of The Exelon Way, approximately 1,200 positions are targeted for elimination by 2004, and another 700 by 2006. Positions identified for elimination in 2003 will be complete by November. The majority of the reductions will come from professional and management employees. Overall, Exelon targets to reduce its workforce by about 1900 positions — or 10 percent — by 2006.
“Exelon is committed to treating its employees fairly and will facilitate voluntary separation agreements wherever possible, “ says Chairman and CEO John Rowe. “To that end, we are providing an updated and improved severance package for all affected employees.”
Eliminating redundancies in job functions is only one aspect of The Exelon Way. The program also focuses on streamlining operations, realigning our supply chain and information technology structure, and realizing opportunities for process improvements throughout the organization.
###
Except for the historical information contained herein, certain of the matters discussed in this news release are 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 the forward-looking statements made by a registrant include those factors discussed herein, as well as the items discussed in (a) the Registrants’ 2002 Annual Report on Form 10-K — ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) the Registrants’ 2002 Annual Report on Form 10-K — ITEM 8. Financial Statements and Supplementary Data:
Exelon — Note 19, ComEd — Note 16, PECO — Note 18 and Generation — Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) 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 release. 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 release.
###
Exelon Corporation is one of the nation’s largest electric utilities with approximately 5 million customers and more than $15 billion in annual revenues. The company has one of the industry’s largest portfolios of electricity generation capacity, with a nationwide reach and strong positions in the Midwest and Mid-Atlantic. Exelon distributes electricity to approximately 5 million customers in Illinois and Pennsylvania and gas to more than 440,000 customers in the Philadelphia area. The company also has holdings in such competitive businesses as energy, infrastructure services, energy services and telecommunications. Exelon is headquartered in Chicago and trades on the NYSE under the ticker EXC.
page 2
Exhibit 99.2
Exelon Investor Conference
August 6, 2003
The Waldorf=Astoria
New York City
Building Value – The Exelon Way
Agenda
| 7:30 a.m.–8:00 a.m | Registration and Continental Breakfast (Astor Salon, 3rd Floor) | |
| Conference Program | (Jade Room, 3rd Floor) | |
| 8:00 a.m.–8:30 a.m | John W. Rowe – Introduction and Strategic Overview | |
| 8:30 a.m.–9:00 a.m | Oliver D. Kingsley, Jr. – Operating Overview | |
| 9:00 a.m.–9:15 a.m | Michael B. Bemis – Energy Delivery Regulatory Overview | |
| 9:15 a.m.–9:30 a.m | John W. Rowe – Evolving Regulatory Framework | |
| 9:30 a.m.–10:00 a.m | Break (Astor Salon) | |
| 10:00 a.m.–10:20 a.m | John F. Young – Generation Strategy | |
| 10:20 a.m.–10:40 a.m | Ian P. McLean – Portfolio Optimization and Risk Management | |
| 10:40 a.m.–11:10 a.m | Robert S. Shapard – Financial Overview | |
| 11:10 a.m.–12:00 p.m | John W. Rowe – Wrap-up/Q&A |
| Exelon Corporation Building Value - The Exelon Way John W. Rowe Chairman & Chief Executive Officer Exelon Investor Conference New York City August 6, 2003 |
| This presentation contains certain 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 the forward-looking statements made by a registrant include those discussed herein as well as those discussed in Exelon Corporation's 2002 Annual Report on Form 10-K in (a) ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Business Outlook and the Challenges in Managing Our Business for Exelon, ComEd, PECO and Generation and (b) ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 19, ComEd-Note 16, PECO-Note 18 and Generation-Note 13, and (c) 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 (Registrants). 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 Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. Forward-Looking Statements |
| Total Return Comparisons 1/1/00 - 6/30/03 Source: Bloomberg |
| Elizabeth Anne Moler EVP, Government & Regulation, Exelon Corp John W. Rowe Chairman & Chief Executive Officer, Exelon Corp Oliver D. Kingsley, Jr. President & Chief Operating Officer, Exelon Corp Randall E. Mehrberg EVP & General Counsel, Exelon Corp Robert S. Shapard EVP & Chief Financial Officer, Exelon Corp Pamela B. Strobel EVP & Chief Administrative Officer, Exelon Corp S. Gary Snodgrass SVP & Chief Human Resources Officer, Exelon Corp Ian P. McLean EVP, Exelon Corp; President, Power Team, Exelon Generation The Exelon Way Team |
| Building on Success Low-cost generation portfolio Large, stable retail customer base No material trading or international exposure Strong balance sheet Positioned to deliver 5% annual earnings growth Experienced management to take Exelon to the next level of excellence - The Exelon Way |
| Today's Agenda Building Value - The Exelon Way 8:00 a.m.-8:30 a.m. John W. Rowe - Introduction and Strategic Overview 8:30 a.m.-9:00 a.m. Oliver D. Kingsley, Jr. - Operating Overview 9:00 a.m.-9:15 a.m. Michael B. Bemis - Energy Delivery Regulatory Overview 9:15 a.m.-9:30 a.m. John W. Rowe - Evolving Regulatory Framework 9:30 a.m.-10:00 a.m. Break 10:00 a.m.-10:20 a.m. John F. Young - Generation Strategy 10:20 a.m.-10:40 a.m. Ian P. McLean - Portfolio Optimization and Risk Management 10:40 a.m.-11:10 a.m. Robert S. Shapard - Financial Overview 11:10 a.m.-12:00 p.m. John W. Rowe - Wrap-up/Q&A |
| Operating Overview Oliver D. Kingsley, Jr. President & Chief Operating Officer Exelon Investor Conference New York City August 6, 2003 |
| Generation Portfolio (1) Based on Exelon Generation's ownership and long-term contracts at 7/31/03, including AmerGen Energy Company, LLC; excludes investment in Sithe Energies, Inc. ECAR: 500 MW Contracted MAAC: 10,665 MW Total 10,415 MW Operating 250 MW Contracted MAIN: 20,164 MW Total 11,028 MW Operating 9,136 MW Contracted SPP: 795 MW Contracted SERC: 900 MW Contracted NPCC: 4,066 MW Operating ERCOT: 3,674 MW Total 2,494 MW Operating 1,180 MW Contracted Total: 40,764 MW (1) 28,003 MW Operating 12,761 MW Contracted |
| Largest U.S. Electric Customer Base ComEd Bundled ComEd Unbundled Alternative Suppliers ComEd Unbundled PPO PECO Bundled PECO Unbundled GWh Deliveries 64204 13226 9630 33589 2943 Total electric customers - 5.1 million 52% 11% 27% 8% 2% |
| Improved Energy Delivery Operations 1999 2000 2001 2002 2003 1999 2000 2001 2002 2003 |
| World-Class Nuclear Operations |
| Focus on Operational Excellence 11 RFOs 6 RFOs 11 RFOs 3 RFOs RFOs-Refueling outages |
| Improvement in Exelon Power |
| Opportunity for Additional Improvement - Energy Delivery SAIFI - 2001 industry actuals; 2002 Exelon actuals American Customer Satisfaction Index (ACSI) - 2002 actuals |
| Exelon Power units are not consistently top quartile in their peer groups Actions: Fleet-wide material condition assessment completed Human performance initiatives Standard programs, processes Asset-by-asset portfolio review underway Data: GKS (Generation Knowledge System) benchmarking community Opportunity for Improvement - Exelon Power |
| Opportunity for Improvement - Exelon Nuclear Exelon Nuclear is closing the production cost gap to top performance compared with other major operators Continued focus on refueling outage execution, forced loss rate, operational excellence 6th lowest cost 5th lowest cost 2nd lowest cost Of the 11 large nuclear fleet operators, Exelon Nuclear was: Lowest cost Highest cost Data: Electric Utility Cost Group |
| The Exelon Way Goals Achieve top-quartile operating and financial performance excellence as measured by industry metrics Deliver at least $300 million in annual cash flow improvement from O&M and Cap Ex by 2004 Grow to more than $600 million in annual cash flow improvement by 2006 Strategy Reshape the Exelon business model to maximize consolidation and integration synergies Create a high-performance organization and culture of excellence Standardize, simplify and strengthen underlying business management processes Put the management in place to make it happen Aggressively pursue significant and sustainable cash flow improvement |
| Standard best programs and processes Reduce resource requirements, duplication; capture synergies Effective process management Enable sustained and replicable good performance Rigorous performance management Focus on productivity improvement Operational improvement and organizational alignment is driving sustainable cost reduction It's working in Nuclear. It's producing results in Power. It's being defined & implemented in Energy Delivery. The Exelon Way is driving it company-wide. The New Play Book |
| Genco Operations and Alignment - What's Different? Nuclear - Continued focus on top performance Power - Optimization and execution Power/Power Team market alignment Regional asset rationalization Sales and Marketing Enhanced marketing focus and leadership in all regions |
| EED will complete the merger $500 million uncaptured savings potential in O&M and capital EED is developing and implementing the model Consolidated organization structure with clear accountabilities Focus on the basics: events, errors, fundamental standards Leadership team and 18 process teams are driving business/organization integration EED Operations and Alignment - What's Different? |
| Supply Chain: > $2 billion total non-fuel spend in 2002 ~ 750 full-time employees ~ $80 million operating costs Integrated supply chain organization will deliver increased value Eliminate redundancy Strategic sourcing and category management Inventory management Vehicle fleet management e-Business payment channel Headcount reductions Sustainable savings opportunities 2004-2006: $120-180 million Corporate Support and Alignment - What's Different? |
| Information Technology: ~ $500 million Exelon IT spend in 2002 ~ 1,200 Exelon and contractor resources New structure consolidates IT, eliminates redundancies Re-prioritize, manage IT project spend Consolidate and reduce headcount Standardize infrastructure and processes Leverage the right outsourcing opportunities Strengthen governance Manage demand Sustainable savings opportunities 2004-2006: $50-70 million Corporate Support and Alignment - What's Different? |
| Exelon Energy Delivery Regulatory Overview Michael B. Bemis President, Exelon Energy Delivery Exelon Investor Conference New York City August 6, 2003 |
| Current Regulatory Structure ComEd The Illinois Electric Service Customer Choice and Rate Relief Law of 1997 Transition period through 2006 Last pre-restructuring rate case - 1994 test year PECO Energy Electricity Generation Customer Choice and Competition Act - 1996 Restructuring Settlement Agreement - 1998 Transition period through 2010 Last pre-restructuring electric rate case - 3/90 test year Last gas rate case - 1988 |
| PECO Transition Structure Generation rate cap expires January 1, 2011 Distribution rate cap expires January 1, 2007 $5.26 billion of stranded investment collected on 12-year amortization schedule with 10.75% return Annual reconciliation of Competitive Transition Charge (CTC) Stranded investment is not recomputed Returns (net income) decrease over time: $137 million in 2003 to $3 million in 2010 |
| ComEd Transition Structure Established a "transition period" through 2006 Provided an opportunity to recover stranded costs, but did not predetermine the amount Recovery mechanisms included: Bundled Rate freeze though 2004 (later extended to 2006) Collection of CTCs from shopping customers using "revenues lost" approach Flexibility to restructure and transfer assets Ability to issue transition bonds securitized by the total regulated revenue stream Established ROE cap with earnings-sharing mechanism |
| "Revenues Lost" Approach Determines CTC Revenue Note: Regulated Revenues represent the average residential revenue/MWh for 2003, which was used for all periods. Other data represents actual averages for historical periods and hypothetical averages for future periods, based on assumption that current factors will not change. Hypothetical data are used for illustrative purposes only and they do not represent Exelon's projections for future rates. Regulated Revenues (from Bundled Rate Customers) Mitigation Factor Market-Based Revenues during transition period (absent CTC) Revenues Lost (recovered by CTC) CTC Energy (MVEC - Market Value Energy Component) Delivery Services |
| 2003 ComEd Regulatory Settlement Addressed major issues awaiting regulatory action: Constructively concluded ComEd Residential Delivery Services rate case Modified calculation of CTC revenue for shopping customers Facilitated extension of full-requirements PPA between ComEd and Generation through 2006 Facilitated continued collection of decommissioning charge revenue through 2006 Supported Provider of Last Resort (POLR) provisions Provided funding for energy-related programs in Illinois |
| Evolving Regulatory Framework John W. Rowe Chairman & Chief Executive Officer Exelon Investor Conference New York City August 6, 2003 |
| Electric Industry Ratemaking Evolution Post Transition Traditional Transition All electric services bundled Rates based on assets owned AFUDC Used and useful Prudency review Separation of regulated and competitive businesses Hybrid of traditional ratemaking and market pricing Stranded investment recovery CTC MVEC Shopping credit Mitigation factor Regulated T&D rates Market-based commodity pricing Rates based on services provided Retail risk management adder Energy procurement charge Customer switching premium A new bundled rate agreement |
| Post-Transition Strategy 2003 2007 Operating Earnings and cash flow growth Balance sheet re-engineering Regulatory Transmission rate case Delivery services rate case Socialize issues and solutions Financial The Exelon Way Optimize generation value |
| The "Status Quo" Scenario Lack of full recovery on T&D service No long-term risk management services High risk for customers (no rate certainty) Avg. bundled retail rev/kWh 2002 2007 7.7 cents 6.4 cents 2.5 cents Avg. T&D Charge 3.9 cents Market- based Energy Charge Note: Numbers represent actual average data for historical periods and hypothetical data for future periods, based on assumption that current factors will not change. Hypothetical numbers are used for illustrative purposes only and they do not represent Exelon's projections for future rates. |
| The "Full-Value Recognition" Scenario Average bundled rate below inflation-adjusted 1996 level Full recovery of T&D costs Market-based energy price Compensation for risk management services 2002 2007 7.7 cents 8.1 cents Avg. bundled retail rev/kWh Avg. T&D Charge Market- based Energy Charge Services Note: Numbers represent actual average data for historical periods and hypothetical data for future periods. Hypothetical numbers are used for illustrative purposes only and they do not represent Exelon's projections for future rates. |
| Building Value - The Exelon Way |
| Generation Strategy John F. Young President, Exelon Power Exelon Investor Conference New York City August 6, 2003 |
| Exelon Generation: An Overview Exelon Generation Competitive energy business of Exelon Exelon Nuclear President: John L. Skolds Operates and maintains Exelon's nuclear assets Nuclear Capacity: 15,788 MW Exelon Power President: John F. Young Operates and maintains Exelon's fossil and hydro units Fossil Capacity: 10,631 MW Hydro Capacity: 1,584 MW Power Team President: Ian P. McLean Manages Exelon Generation's portfolio risk and optimizes near-term margins Contracts under management: 12,761 MW Exelon Generation: A world-class operator of nuclear power generation A broad based portfolio of gas, oil, coal, wind and hydro generation A experienced leader in wholesale power marketing and risk management |
| Well-balanced portfolio in Midwest and Mid Atlantic Significant generation presence in ERCOT/South and NEPOOL Total Owned Gen: Contracted Gen: Total Generation: 28,003 MW 12,761 MW 40,764 MW Mid Atlantic Owned Gen: Contracted Gen: Total Gen: PECO Control Area Peak Load: 10,415 MW 250 MW 10,665 MW 8,250 MW ERCOT/South Owned Gen: Contracted Gen: Total Gen: Load: 2,494 MW 2,875 MW 5,369 MW 2,334 MW New England Total Owned Gen: 4,066 MW Nuclear Hydro Coal Intermediate Peaker Midwest Owned Gen: Contracted Gen: Total Gen: ComEd Control Area Peak Load: 11,028 MW 9,636 MW 20,664 MW 22,100 MW Owned generation includes Exelon's share of AmerGen and excludes Sithe assets. Regional Summary |
| Evolving Power Markets Exelon Generation - Consistent over Time: Balancing power generation with load and wholesale trading Asset-led physical strategy and added balance through financial markets Financial results - What you see is what you get 1994 1996 1998 2000 2002 2004 1992 High Growth Asset lite strategy Convergence of power and gas markets Markets become more financial Access to capital markets Infancy Large physical markets Off-system sales of excess length Early stages of power trading Back to Basics Markets become more physical Collapse of the trading business model The future? |
| Exelon Generation's Strategy Exelon's Vision To become the best and the most consistently profitable electric and gas company in the United States Exelon Generation's Strategy Create value through proven world class operational excellence and superior market based commercial experience Business Strategy Goals and Objectives Key Skills Key Skills World class nuclear operations Demonstrated ability to extract value from fossil and hydro assets Financial valuation skills across commodities and products Knowledge of both power and fuels markets Goals and Objectives Generate electricity reliably and at a lower cost than our competitors Achieve top quartile operating performance on a sustained basis Optimize investment in assets consistent with market environment Leverage our commercial expertise to optimize our portfolio and mitigate risk |
| Generation: Value Creation Linking generation and load Continuous rationalization of assets: buy/sell/swap/retire/reinvest Understanding market dynamics, transmission, customers and environmental issues Execution of performance enhancement strategy for the entire fleet Aggressive management of fuel, O&M and capital cost Operational Excellence Maximize Exelon Generation Portfolio Value Long-Term Portfolio Balance Portfolio Optimization and Risk Management Reducing uncertainty by physical and financial hedging of power and underlying fuel Optimizing generation and load portfolio in the wholesale market Assets Assets Assets |
| Portfolio Optimization and Risk Management Ian P. McLean President, Power Team Exelon Investor Conference New York City August 6, 2003 |
| Value Added Intermediary Nuclear Fossil Hydro Generation Exelon Power Team ComEd PECO Wholesale Power Markets Fuel Markets Affiliates Contracts Power Team manages the interaction between the generation portfolio and the wholesale customers in order to reduce risk and optimize Exelon Generation profitability in the near term. |
| Risk Management Framework Load Only Long View Long-Term Portfolio Balancing Portfolio Optimization & Risk Management Approach to Risk Management over Time Approach To Managing Volatility And Optimizing Value In 2003: Established hedge ratio goal of 80% or more Grew hedge position to 90+% on average for year For 2004: Establish portfolio and regional hedge book limits based on earnings-at-risk proxy and considering: Market liquidity and depth Internal hedges Sell forward or utilize options to stay within limits Optimize positions to provide flexibility and maximize earnings while staying within limits (leave some energy to spot) Increase hedge ratio in short run Do not over hedge in any region Purchase underlying fuel for any forward sales Risk appetite Load uncertainty There are three distinct time horizons from which to view risk management. Increasing |
| Risk Management 0% 1% 2% 3% 4% 5% 6% - -743 - -578 - -413 - -248 - -83 83 248 413 578 743 $ Million Portfolio with load + forward sales Portfolio with load as a hedge Portfolio with target hedges Range at 90% confidence level Probability Margin Uncertainty ($) Portfolio Characteristics Generally long - to address full requirements PPAs Internal load provides 50% fixed price hedge Internal ComEd CTC hedge and Texas PPAs provide additional protection Risk Issues Reliability - Meeting load obligations in ComEd, PECO Financial (All Regions) - Power Prices & Volatility Fuel Prices & Volatility Load & Volatility Credit Issues |
| Midwest Portfolio * Assuming $5/MMBtu gas price ** Excludes recent decision to terminate 578 MW of coal options Indiana Illinois Chicago Market Dynamics The Midwest portfolio is in MAIN and ECAR. Predominantly a bilateral market Significant transmission constraints ComEd integration into PJM (est. 11/03) expected to increase volume of transactions MAIN: 25% reserve margin, 57,000-MW peak demand, coal = 33% of total capacity ECAR: 30% reserve margin, 100,000-MW peak demand, coal = 50% of total capacity Supply/demand equilibrium not expected until 2009/2010 18,350 Peak Load (MW) 74,500 Annual GWh (2004) Demand $21.50 20,664 Total Capacity $60.00 3,768 Peakers* $33.00 1,084 Intermediate $16.00 5,134** Coal $4.50 10,678 Nuclear Avg. Variable Cost ($/MWh) Plant 2003 Capacity (MW) |
| Midwest: Key Elements Minimal oil capacity in the portfolio Oil Spark Relatively insignificant spark capacity as compared to base-load length Gas Spark Oil not significantly on the margin in the region Oil Substantial base-load capacity ? Long gas position Gas increasingly on the margin Natural Gas Comments Impact Commodity Significant Insignificant 2003: +/- $1/MWh ATC power 2004: +/- $1/MWh ATC power $ 10 M $ 28 M ATC - Around the clock Risk Management 2003 Portfolio around 90% sold forward for 2003 and the underlying fuel purchased Put in place option strategies to mitigate weather and power/gas price risks Given significant base-load capacity, region still exposed to power price movements Risk Management 2004 Portfolio around 75% sold forward for 2004 and the underlying fuel purchased - limited ability to sell forward in financial markets Mitigated off-peak length by releasing 578 MW of high-priced Midwest Generation coal contracts Acquire intermediate products to complement existing asset portfolio Actively balancing generation and load through bilateral markets |
| Pennsylvania Maryland New Jersey Delaware Mid-Atlantic Portfolio * Assuming $5/MMBtu gas price Plant 2003 Capacity (MW) Avg. Variable Cost ($/MWh) Nuclear 5,110 $5.00 Hydro 1,584 NA Coal 1,434 $20.00 Intermediate & Wind 250 $40.00 Peakers* 2,287 $80.00 Total Capacity 10,665 Demand Annual GWh (2004) 34,000 PPA Peak Load (MW) 6,858 Market Dynamics All the Mid-Atlantic portfolio assets are in the PJM region. Centrally dispatched power pool 23% reserve margin, 63,800-MW peak demand (PJM and PJM West) Coal = 28% of total capacity Combined-cycle gas turbines (CCGTs) are on the margin a majority of on-peak hours and many summer off-peak hours Supply/demand equilibrium not expected until 2009/2010 |
| Mid-Atlantic: Key Elements Significant Insignificant Commodity Impact Comments Natural Gas Substantial base-load capacity and oil- fired generation ? Long gas position Gas increasingly on the margin Oil Oil on the margin a significant proportion of the time Gas Spark Relatively insignificant spark capacity as compared to base-load length Oil Spark Significant oil-based capacity in the portfolio 2003: +/- $1/MWh ATC power 2004: +/- $1/MWh ATC power $ 2 M $ 6 M Risk Management 2003 Over 95% power sold forward and underlying fuel purchased Higher than expected native load required buyback of forward sales Upside and downside protection through options Risk Management 2004 Portfolio in 2004 fairly well hedged Acquire intermediate products to complement existing asset portfolio Further hedging limited to upside and downside protection through option strategies |
| ERCOT/South Portfolio Plant Capacity Avg. Variable Cost ($/MWh) Combined Cycle* 1,975 MW $40.00 Peakers* 3,394 MW $60.00 Total Capacity 5,369 MW Load** 2,334 MW * Assuming $5/MMBtu gas price ** TXU tolling deal totaling 2,334 MW Texas Oklahoma Georgia Market Dynamics The portfolio assets are in the ERCOT, SPP and Southern Company (SoCo) regions. ERCOT: Centrally dispatched power pool, 56% reserve margin, 57,629-MW peak, gas on the margin during peak hours, supply/demand equilibrium expected 2014 SPP & SoCo: Bilateral markets only, 43,000-MW peak (SPP), 48,000-MW peak (SoCo), reserve margins 21% (SPP), 28% (SoCo); gas on the margin during peak months, supply/demand equilibrium expected 2009/2010 |
| ERCOT/South: Key Elements Significant Insignificant Minimal oil capacity Oil Spark The entire portfolio is spark based; 40% are high-efficiency combined-cycle units Gas Spark Oil not on the margin in the region Oil Gas on the margin a significant proportion of the time (over 80% of the hours); however, spark determines regional profit Natural Gas Comments Impact Commodity 2003: +/- $1/MWh ATC spark 2004: +/- $1/MWh ATC spark $ 2 M $ 7 M Risk Management 2003 Portfolio over 80% sold in Q3 and the underlying fuel purchased; however, portfolio exposed to market risks in Q4 as only 60% sold forward Wolf Hollow not yet commercial; will sell forward over 70% of generation once commercial Risk Management 2004 Portfolio largely unsold in 2004; currently, only 45% sold (excludes toll to TXU) - limited ability to sell forward in financial markets In the process of selling generation and purchasing underlying gas for 2004 through bilateral markets - targeting a hedge ratio of around 80% |
| New England Portfolio * Assuming $5/MMBtu gas price Plant Capacity Avg. Variable Cost ($/MWh) Base-load* 2,421 MW $40.00 Peakers* 1,645 MW $60.00 Total Capacity 4,066 MW Massachusetts Maine Boston Market Dynamics All of the New England portfolio assets are in the NEPOOL region. Centrally dispatched pool with locational pricing 30% reserve margin in 2003, equilibrium expected in 2009/2010 Generation mix is predominately new CCGTs and old dual fuel units Majority of load served through competitive auctions NEPOOL governance weighted towards transmission and load interests |
| New England: Key Elements Significant Insignificant Commodity Impact Comments Natural Gas Gas increasingly on the margin (over 50% of the on-peak hours) Oil Over time the importance of oil in the region decreases Oil on the margin a significant proportion of the time (around 45%) Gas Spark Significant proportion of portfolio is gas based Oil Spark Oil-based capacity in the portfolio is insignificant 2003: +/- $1/MWh ATC spark $ 4 M Risk Management 2003 Around 60% of generation sold forward and underlying fuel purchased Fore River not sold forward due to uncertainty around commercial operation date Continuing to evaluate forward sales in light of bank financing issues |
| In Summary... Real assets, real financial results Linked load and generation strategy Focused risk management and short-term value creation |
| Financial Overview Robert S. Shapard Executive Vice President & Chief Financial Officer Exelon Investor Conference New York City August 6, 2003 |
| Baseline and Goals Reporting and Timeline The Exelon Way |
| O&M and CapEx Targets ($ millions) 2004 Annual Impact O&M* CapEx Total GenCo $ 80 $ 65 $ 145 $ 115 $ 125 $ 240 EED 130 135 265 215 295 510 Total $ 210 $ 200 $ 410 $ 330 $ 420 $ 750 Cash Flow Summary 2004 Impacts GenCo $ 50 $ 65 $ 115 $ 71 $ 125 $ 196 EED 81 135 216 133 295 428 Total $ 131 $ 200 $ 331 $ 204 $ 420 $ 624 O&M CapEx Total 2006 Annual Impact O&M* CapEx Total Key Points Severance costs expected to occur in 3Q/4Q 2003 and most likely recur in late 2004/early 2005 for second stage reductions Anticipated staffing reduction target of ~1,200 by 2004 and 1,900 by 2006 Beyond severance, overall costs-to-achieve associated with information technology, facilities and third-party costs are not expected to be significant Savings targets are net of costs-to-achieve other than severance 2006 Impacts O&M CapEx Total * Pre-tax |
| Total Spend Baseline GenCo $ 1,200 $ 850 $ 2,050 EED 1,050 975 2,025 Enterprises 775 - 775 Corporate/BSC 1,050 125 1,175 Total $ 4,075 $ 1,950 $ 6,025 2003 Cost Baseline ($ millions) Total O&M* CapEx Total Spend Business Unit Considerations Based upon 2003 year-end targets Total Exelon O&M and CapEx to be addressed Approximately 50% of total O&M spend is labor related Enterprises largely addressed through divestment program * Pre-tax |
| Calendar May/June July August/September October - December Key Activities High-level organizational models defined First-cut targets affirmed by Teams New GenCo and EED high-level organizations announced Operating process identified Savings initiative tracking in place for "quick hits" Finalize detailed functional and Business Unit organization structures Complete 2004 opportunity assessments Prepare implementation plans for 2004 savings Staffing reduction (for 2004 targets) to be completed by mid-November Process redesign and implementation continuing High-Level Timeline |
| Financial Outlook |
| Build Value through Consistent Profitability Earnings Time Earnings Uncertainty Exelon Action Plan Load Migration & Competitive Market Evolution Electric & Gas Volatility EBG; InfraSource Sale Low-Cost, World-Class Operations IL & PA Transition Periods Pensions & Benefits Exelon Way |
| Build Value through Consistent Profitability Operating Earnings Per Share* Time $4.50 $4.49 $4.30 $5.00 "Top End" $4.70 $4.85 $4.83 $4.45 $5.45 $5.15 $3.86 2000 2001 2002 2003E 2004E * See end of presentation material for reconciliation to GAAP data. Note: Current 2003E operating EPS guidance is $4.80 to $5.00. |
| Exelon Consolidated Key Assumptions |
| EED Financial Outlook Note: See end of presentation material for reconciliation to GAAP data. |
| Genco Financial Outlook Note: See end of presentation material for reconciliation to GAAP data. |
| ECP $59 Initial Investment Asset Sales UPH ECP Net Investment Thermal Eval GW ECP Energy Thermal Closed Ops Other 4/30/02 BV East 2 1.8 1.65 1.57 1.48 1.28 1.26 1.08 0.98 0.885 West North 1.8 1.65 1.57 1.48 1.28 1.26 1.08 0.98 0.885 0.775 ($ millions) Investment 6/30/03 Book Value $2,000 $(200) Thermal Revaluation $(150) $(80) Extant Nextwave/ Kinetic/ Other Goodwill Adjustment $(90) $660 Other $(105) InfraSource $560 Comm $280 Therm $290 Energy $280 UPH $160 Capital Partners $200 Svcs $140 Other $90 Power Holdings Equip (UPH) $(270) $1,570 Net Investment after Cash Returned Cash Generated from Sales $(235) $(95) $(95) Thermal Closed Ops Energy Revalued Assets Booked Losses $2,000 $0 $1,000 $1,500 $500 ATT NOTE: Signed agreements to sell InfraSource businesses are expected to generate $280 million in cash. Capital Partners 6/03 Impairment $(20) Thermal $95 Services $90 Other $160 InfraSource sold: $280 $1,290 InfraSource $35 $280 Revaluation of Enterprises' Assets |
| Exelon Consolidated Financial Outlook Note: See end of presentation material for reconciliation to GAAP data. |
| Exelon Consolidated Balance Sheet |
| 2002 Actual CTC Ent. Losses EBG Interest Sales MWG Options 2004 Gas EW_Infla Invisible dataset 4.65 4.65 4.8 4.94 5.01 5.13 5.09 5.09 Green 5 0.35 0.15 0.14 0.07 0.12 0.06 5.19 0.1 0.4 2003E Guidance 2004 E Gas Price Risks Exit Exelon New England ComEd CTC/RTO PECO CTC/Amort. Stop Enterprises Losses MW Gen Options Interest Exelon Way Other Risks and Opportunities +/- CTC Reset +/- Weather +/- Economy - - Inflation Expected EPS Drivers $5.19 Sales Growth 2004 EPS Guidance: $5.15 - $5.45 |
| Conference Wrap-up John W. Rowe Chairman & Chief Executive Officer Exelon Investor Conference New York City August 6, 2003 |
| Valuation Measures P/E Earnings per Share Earnings per Share Dividends Yield 2004E (X) 2-Yr CAGR 2000-2002A (%) 2-Yr CAGR 2002A-2004E (%) 5-Yr CAGR 1997-2002A (%) (%) Exelon 11.0 11.9 4.2 2.2 3.5 Entergy 12.6 10.5 4.6 -5.5 3.5 FPL Group 12.1 4.7 3.1 3.8 3.9 Dominion Res. 11.9 20.4 2.4 0 4.3 Southern 14.7 10.6 2.1 0.8 4.9 Cinergy 12.3 1.3 1.5 0.1 5.4 Progress Energy 10.6 12.5 0.3 3.0 5.5 DTE Energy 9.5 7.4 -1.1 0 5.8 AEP 12.2 3.5 -11.0 0 5.0 Duke Energy 12.4 -5.4 -14.6 0.2 6.3 Average 11.9 7.7 -0.9* 0.5 4.8 * 2.1% CAGR excluding AEP and Duke Sources: Thomson First Call, Bloomberg Note: P/E and yield statistics as of 7/31/03 A=Actual; E=Estimate; CAGR=Compound annual growth rate |
| Building Value - The Exelon Way |
Exhibit 99.3
Reconciliation of GAAP Reported and Operating Earnings per Share
2000 Reported EPS |
$ | 2.87 | ||
Change in common shares |
(1.06 | ) | ||
Extraordinary items |
(0.07 | ) | ||
Cumulative effect of accounting change |
0.01 | |||
Unicom pre-merger results |
1.58 | |||
Merger-related costs |
0.68 | |||
Pro forma merger accounting adjustments |
(0.15 | ) | ||
2000 Pro Forma Operating EPS |
$ | 3.86 |
2001 Reported EPS |
$ | 4.43 | ||
Cumulative effect of adopting SFAS 133 |
(0.04 | ) | ||
Employee severance cost |
0.09 | |||
Litigation reserves |
0.03 | |||
Net loss on investments |
0.02 | |||
CTC prepayment |
(0.02 | ) | ||
Wholesale rate settlement |
(0.01 | ) | ||
Settlement of transition bond swap |
(0.01 | ) | ||
2001 Pro Forma Operating EPS |
$ | 4.49 |
2002 Reported EPS |
$ | 4.44 | ||
Transition loss on implementation of FAS 141 and 142 |
0.71 | |||
Gain on sale of AT&T Wireless |
(0.36 | ) | ||
Employee severance costs |
0.04 | |||
2002 Pro Forma Operating EPS |
$ | 4.83 |
Exelon Energy Delivery
Consolidated Statement of Income
(unaudited)
(in millions, except per share data)
| Six Months Ended June 30, 2003 | |||||||||||||
| Pro Forma | |||||||||||||
| GAAP (a) | Adjustments | Pro Forma | |||||||||||
Operating revenues |
$ | 4,964 | $ | — | $ | 4,964 | |||||||
Operating expenses |
|||||||||||||
Purchased power |
1,918 | — | 1,918 | ||||||||||
Fuel |
257 | — | 257 | ||||||||||
Operating and maintenance |
744 | (41 | )(b) | 703 | |||||||||
Depreciation and amortization |
427 | — | 427 | ||||||||||
Taxes other than income |
258 | — | 258 | ||||||||||
Total operating expenses |
3,604 | (41 | ) | 3,563 | |||||||||
Operating income |
1,360 | 41 | 1,401 | ||||||||||
Other income and deductions |
|||||||||||||
Interest expense |
(383 | ) | — | (383 | ) | ||||||||
Distributions on preferred securities
of subsidiaries |
(22 | ) | — | (22 | ) | ||||||||
Equity in earnings of unconsolidated
affiliates |
— | — | — | ||||||||||
Other, net |
43 | (12 | )(b) | 31 | |||||||||
Total other income and deductions |
(362 | ) | (12 | ) | (374 | ) | |||||||
Income before income taxes and cumulative
effect of changes in accounting principles |
998 | 29 | 1,027 | ||||||||||
Income taxes |
382 | 12 | 394 | ||||||||||
Income before cumulative effect of changes
in accounting principles |
616 | 17 | 633 | ||||||||||
Cumulative effect of changes in accounting
principles, net of income taxes |
5 | (5 | )(c) | — | |||||||||
Net income |
$ | 621 | $ | 12 | $ | 633 | |||||||
Effect of pro forma adjustments on earnings per |
|||||
Exelon Corporation’s average diluted common share recorded in |
|||||
accordance with GAAP: |
|||||
March 3 ComEd Settlement Agreement |
$ | (0.05 | ) | ||
Cumulative effect of adopting SFAS No. 143 |
(0.02 | ) | |||
Total pro forma adjustments |
$ | (0.07 | ) | ||
| (a) | Results reported in accordance with accounting principles generally accepted in the United States (GAAP). | |
| (b) | Pro forma adjustment for the March 3 ComEd Settlement Agreement. | |
| (c) | Pro forma adjustment for the cumulative effect of adopting SFAS No. 143. |
Exelon Generation Company, LLC
Consolidated Statement of Income
(unaudited)
(in millions, except per share data)
| Six Months Ended June 30, 2003 | |||||||||||||
| Pro Forma | |||||||||||||
| GAAP (a) | Adjustments | Pro Forma | |||||||||||
Operating revenues |
$ | 3,765 | $ | — | $ | 3,765 | |||||||
Operating expenses |
|||||||||||||
Purchased power |
1,642 | — | 1,642 | ||||||||||
Fuel |
706 | — | 706 | ||||||||||
Operating and maintenance |
943 | — | 943 | ||||||||||
Depreciation and amortization |
91 | — | 91 | ||||||||||
Taxes other than income |
88 | — | 88 | ||||||||||
Total operating expenses |
3,470 | — | 3,470 | ||||||||||
Operating income |
295 | — | 295 | ||||||||||
Other income and deductions |
|||||||||||||
Interest expense |
(38 | ) | — | (38 | ) | ||||||||
Distributions on preferred securities
of subsidiaries |
— | — | — | ||||||||||
Equity in earnings of unconsolidated
affiliates |
37 | — | 37 | ||||||||||
Other, net |
(134 | ) | 200 | (b) | 66 | ||||||||
Total other income and deductions |
(135 | ) | 200 | 65 | |||||||||
Income before income taxes and cumulative
effect of changes in accounting principles |
160 | 200 | 360 | ||||||||||
Income taxes |
71 | 70 | 141 | ||||||||||
Income before cumulative effect of changes
in accounting principles |
89 | 130 | 219 | ||||||||||
Cumulative effect of changes in accounting
principles, net of income taxes |
108 | (108 | )(c) | — | |||||||||
Net income |
$ | 197 | $ | 22 | $ | 219 | |||||||
Effect of pro forma adjustments on earnings per |
|||||
Exelon Corporation’s average diluted common share recorded in |
|||||
accordance with GAAP: |
|||||
Impairment of Exelon’s investment in Sithe Energies, Inc. |
$ | (0.40 | ) | ||
Cumulative effect of adopting SFAS No. 143 |
0.33 | ||||
Total pro forma adjustments |
$ | (0.07 | ) | ||
| (a) | Results reported in accordance with accounting principles generally accepted in the United States (GAAP). | |
| (b) | Pro forma adjustment for the impairment of Exelon’s investment in Sithe Energies, Inc. | |
| (c) | Pro forma adjustment for the cumulative effect of adopting SFAS No. 143. |
| Exelon New England Plants June 10, 2003 Status Capacity (MWs) Fuel Heat Rate (Btu/kWh) 2003 Projected Capacity Factor Fore River (Base-load) Construction 807 Gas/Oil 6,850 > 50% Total Merchant Under Constr. 807 Framingham 1 (Peaking) Operating 13 Oil 13,500 < 5% Framingham 2 (Peaking) Operating 11 Oil 13,500 < 5% Framingham 3 (Peaking) Operating 13 Oil 13,500 < 5% Mystic 4 (Intermediate) Operating 135 Oil 9,900 < 5% Mystic 5 (Intermediate) Operating 130 Oil 10,200 < 5% Mystic 6 (Intermediate) Operating 138 Oil 10,300 < 5% Mystic 7 (Intermediate) Operating 592 Gas/Oil 10,400 30-40% Mystic 8 (Base-load) Operating 807 Gas 6,850 > 70% Mystic 9 (Base-load) Operating 807 Gas 6,850 > 70% Mystic CT (Peaking) Operating 12 Oil 13,500 < 5% New Boston 1 (Peaking) Operating 380 Gas/Oil N/A New Boston 3 (Peaking) Operating 20 Oil N/A West Medway 1 (Peaking) Operating 55 Gas/Oil 13,500 < 5% West Medway 2 (Peaking) Operating 55 Gas/Oil 13,500 < 5% West Medway 3 (Peaking) Operating 55 Gas/Oil 13,500 < 5% Wyman 4 (Peaking) Operating 36 Oil 10,400 < 5% Total Merchant in Operation 3,259 Total MWs 4,066 |
| Sithe Energies Assets Merchant Plants Batavia New York 1 Gas Intermediate 51 Massena New York 1 Gas/Oil Intermediate 68 Ogdensburg New York 1 Gas/Oil Intermediate 71 Cardinal Canada 1 Gas Base-load 157 Qualifying Facilities Allegheny 5, 6, 8, 9 Pennsylvania 4 Hydro Intermediate 50 Bypass Idaho 1 Hydro Base-load 10 Elk Creek Idaho 1 Hydro Base-load 2 Greeley Colorado 1 Gas Base-load 49 Hazelton Idaho 1 Hydro Base-load 9 Independence New York 1 Gas Base-load 617 Ivy River North Carolina 1 Hydro Base-load 1 Kenilworth New Jersey 1 Gas Base-load 26 Montgomery Creek California 1 Hydro Base-load 3 Naval Station California 1 Gas/Oil Base-load 47 Naval Training Center California 1 Gas/Oil Base-load 22 North Island California 1 Gas/Oil Base-load 34 Oxnard California 1 Gas Base-load 48 Rock Creek California 1 Hydro Base-load 4 Sterling New York 1 Gas Intermediate 55 Under Construction Total TEG 1, 2 Mexico Coke Base-load Type of Plant Station Location No. of Units Fuel Dispatch Type Net Generation Capacity (MW) 4 347 18 977 2 228 24 1,552 The following table shows Sithe's principal assets as of December 31, 2002: |
| Midwest Generation PPA Options In 2002, we released 4,411 MWs of options; in 2003, we have 3,043 MWs of options to exercise or release for 2004. We released 578 MWs on 6/24/03 and will decide on remaining 1,778 MWs by early October. Note: All Midwest Gen contracts expire after 2004. Coal PPA (MWs) Coal PPA (MWs) Collins PPA (MWs) Peakers PPA (MWs) Total (MWs) Non-option Option Collins PPA (MWs) Peakers PPA (MWs) Total (MWs) 2002 Capacity 5,645 5,645 2,698 807 9,150 2002 Decision 1,696 3,949 Released 1,614 Released 113 Released 4,411 2002 Decision Released 2,684 Released 2,684 Released 1,614 Released 113 Released 4,411 2003 Capacity 2,961 2,961 1,084 694 4,739 Pending 2003 Decision 1,696 1,265 May release up to 1,084 May release up to 694 May release up to 1,778 (remaining options) Pending 2003 Decision Released 578 Released 578 May release up to 1,084 May release up to 694 May release up to 1,778 (remaining options) Projected 2004 Capacity 2,383 2,383 0 - 1,084 0 - 694 2,383 - 4,161 |
| Political & Regulatory Environment - IL Illinois Commerce Commission New Chairman and two new Commissioners Three Democrats, one Republican, one Independent Legislature (a new day in Springfield) First Democratic Governor in 26 years Democratically controlled House and Senate Only one Republican Constitutional Officer (Treasurer) |
ComEd Restructuring Legislation
Enacted Dec. 1997
Rate Reductions
| • | Residential - | 15% effective 1/1/98 ~ $400 million | ||
| 5% effective 10/1/2001 ~ $100 million |
Direct Access Phase-In Schedule
| • | Residential | |||
| 5/1/2002 | 100% of residential customers have supplier choice. |
| • | Commercial and Industrial, Governmental |
All C&I customers had supplier choice effective 12/31/00.
Transition Cost Recovery Provisions
| 1) | Bundled rates are frozen through 2006 (originally 2004) at 1996 levels after taking the residential rate reductions described above. | |
| 2) | Unbundled delivery service rates apply to customers who choose an alternate supplier or the market rate for energy (ComEd PPO). |
| • | Utilities recover transition costs via a Competitive Transition Charge (CTC) from customers who select an alternate supplier. The CTC will apply through 2006 for all classes. The CTC will be calculated based on the following formula: |
| CTC | = | Tariff/contract revenues minus | ||
| Delivery service revenue minus | ||||
| Market value of electricity minus | ||||
| Mitigation factor |
(See current and proposed delivery rate schedules attached.)
Mitigation Factor
The mitigation factor is a credit averaging 0.5 cents/kWh offered by the utility to delivery service only customers.
| • | The mitigation factor for commercial and industrial customers is: |
| 10/1/99-12/31/02 | 0.5 cents per kWh or 8% | |
| 2003-2004 | 0.5 cents per kWh or 10% | |
| 2005 | 0.6 cents per kWh or 11% | |
| 2006 | 0.9 cents per kWh or 12% |
| • | The mitigation factor for residential customers is calculated as a percentage of base rates after the rate reductions are in effect. The applicable percentages are as follows: |
| 2002 | 6% of base rates after rate reductions | |
| 2003-2004 | 7% of base rates after rate reductions | |
| 2005 | 8% of base rates after rate reductions | |
| 2006 | 10% of base rates after rate reductions |
Transition Period Provision
During the transition period utilities will be able to recognize, sell or assign assets; retire or remove plants from service; unbundle or restructure tariffs on a revenue neutral basis (with impact limitations described in Earnings and Viability below); accelerate depreciation or amortization or assets without ICC approval. The ICC could intercede if it believed the transaction jeopardized reliable service.
Earnings and Viability
The maximum allowable rate of return will be pegged to the 30-year T-Bond rate, plus 8.5%. If earnings exceed the allowed rate of return by more than 1.5%, 50% of the excess earnings would be shared with customers. If the rate of return is below the T-bond Rate, the utilities can apply to the ICC for a rate increase.
Securitization
Utilities are allowed to utilize securitization of transition period revenues as a means to mitigate stranded costs. The proceeds primarily are to be used to retire debt and equity, and to repay or retire fuel obligations if the Commission finds such use is the public interest.
Amount allowable for securitization is capped by 50% of capitalization. In December 1998, ComEd securitized $3.4 billion.
| ComEd CTC Calculation Bundled Base Rate Average rate by customer class, frozen through 2006 per 1997 Illinois legislation DST Rate Average rate for distribution and transmission services per published tariff Mitigation Factor Guaranteed savings for customers, currently the greater of 10% of the bundled rate or $0.005/kWh MVEC Market value energy component adjusted annually on June 1 CTC Competitive transition charge for recovery of investments made prior to restructuring 100-400 kW Avg. Demand Cents/kWh Bundled Rate 7.428 - DST Rate 1.520 Per published tariff by demand class - Mitigation 0.743 Per 1997 Illinois legislation - MVEC 3.896 Avg. 12-month forward energy prices of trade and bid/ask data from 2/24-3/21/03 = CTC 1.269 |
| ComEd MVEC - How It Works June 2001 March 2002 June 2002 March 2003 June 2003 Bundled 7.428 Energy Prices 7.428 Energy Prices 7.428 DST 1.368 Energy Prices 1.368 Energy Prices 1.520 Mitigation 0.594 Energy Prices 0.594 Energy Prices 0.743 MVEC 5.053 Energy Prices 2.660 Energy Prices 3.896 CTC 0.413 Energy Prices 2.806 Energy Prices 1.269 Changes in MVEC cause inverse change to CTC (100-400 kW avg. demand): Customer Impact Switching (retail electric suppliers (RES) only) as a percent of total 2002 GWh: Small C&I - 17% Large C&I - 35% Total - 15% Potential reduction in CTC revenue beginning 6/03 from customers who buy energy from alternate suppliers Creates potential switching opportunity for other customers |
| ComEd ROE Cap - Earnings Sharing Formula Applies through the end of the transition period (Dec. 31, 2006) Index Calculation: 12-month simple average of "Monthly Treasury Long-Term Average Rates" Plus: 7% Index Adder Plus: 1.5% Index Margin ComEd's two-year average ROE must exceed the two-year average of this index for the same two years before invoking a 50% earnings sharing provision Only the incremental earnings contributing to the percentage in excess of the index is subject to sharing Goodwill is included as equity for purposes of calculating ComEd's ROE |
April 28, 2003
Attachment B1:p 1 of 1
Commonwealth Edison Company
Determination of Nonresidential Customer Transition Charge (Summary Page)
Based on Market Value Defined in Rider PPO — Power Purchase Option (Market Index) Applicable Period A (June 2003 — May 2004)
(All units are in cents per kilowatt-hour)
| Base Rate Revenue | Delivery Service | Mitigation | June 2003 - May 2004 | ||||||||||||||||||
| (1)(2) | Revenue(1)(3) | Market Value (4) | Amount (5) | CTC(6)(7) | |||||||||||||||||
| (A) | (B) | (C) | (D) | (E)=(A)-(B)-(C)-(D) | |||||||||||||||||
Customer Transition Charge Customer Class |
|||||||||||||||||||||
Nonresidential Delivery Service Customers |
|||||||||||||||||||||
With Only Watt-hour Only Meters |
11.258 | 3.756 | 4.028 | 1.126 | 2.348 | ||||||||||||||||
0 kW to and including 25 kW Demand |
9.288 | 2.161 | 3.954 | 0.929 | 2.244 | ||||||||||||||||
Over 25 kW to and including 100 kW Demand |
8.344 | 1.908 | 3.944 | 0.834 | 1.658 | ||||||||||||||||
Over 100 kW to and including 400 kW Demand |
7.428 | 1.520 | 3.896 | 0.743 | 1.269 | ||||||||||||||||
Fixture-included Lighting Nonresidential Delivery Service Customers |
13.554 | 9.754 | 3.059 | 1.355 | 0.000 | ||||||||||||||||
Street Lighting Delivery Service Customers — Dusk to Dawn |
3.852 | 1.801 | 3.047 | 0.500 | 0.000 | ||||||||||||||||
Street Lighting Delivery Service Customers — All Other Lighting |
7.172 | 1.794 | 3.514 | 0.717 | 1.147 | ||||||||||||||||
Railroads Delivery Service Customers (8) |
|||||||||||||||||||||
Pumping Delivery Service Customers |
6.465 | 1.418 | 3.684 | 0.647 | 0.716 | ||||||||||||||||
Notes:
| (1) | Transfer from Column (H) and Column (M) of Determination of Customer Transition Charge, on Pages 5 to 12 of attached work papers. | |
| (2) | Base rate revenues consist of customer, demand, and energy charges. Base rate revenues do not include facility, meter, or other equipment rentals, franchise fees or other franchise cost additions, fuel adjustment clause charges, decommissioning expense adjustment clause charges, taxes, local government compliance clause charges, compensation for energy generated by a person or entity other than ComEd, or Renewable Energy Resources and Coal Technology Development Assistance Charge and Energy Assistance Charge for the Supplemental Low-Income Energy Assistance Fund. | |
| (3) | The amount of revenue that the Company would receive under Rate RCDS — Retail Customer Delivery Service (Rate RCDS) and Rider ISS — Interim Supply Service (Rider ISS) for standard delivery of energy to customers in the CTC Customer Class. | |
| (4) | The Market Value for a CTC Customer Class has the same value as the per kilowatt-hour Load Weighted Average Market Value (LWAMV) as defined in Rider PPO — Power Purchase Option (Market Index) for the applicable customer class for Applicable Period A. | |
| (5) | The mitigation amount as defined in Rate CTC is the greater of 0.5 cents per kilowatt-hour or 10% of the base rate revenue for the calendar years 2003 and 2004. | |
| (6) | This Applicable Period A Customer Transition Charge (CTC) is not applicable if you are taking service under a multi-year CTC option under Rider CTC — MY — Customer Transition Charges — Multi-Year (Rider CTC-MY). Applicable CTCs under a multi-year CTC option are provided on pages 2 through 4. | |
| (7) | CTCs are subject to change without specific notice if one of the components used in the determination of the CTC, as described in Rate CTC, is modified. If the CTC is equal to zero, this account will not be eligible for service under Rider PPO — Power Purchase Option (Market Index) (Rider PPO). | |
| (8) | There are two customers in the Railroads class and each customer will have a Customer-specific CTC. |
April 28, 2003
Attachment B1 R:p 1 of 1
Commonwealth Edison Company
Determination of Residential Customer Transition Charge (Class Summary Page)
Based on Market Value Defined in Rider PPO — Power Purchase Option (Market Index) Applicable Period A (June 2003 — May 2004)
(All units are in cents per kilowatt-hour)
| Base Rate Revenue | Delivery Service | Mitigation | June 2003 - May 2004 | ||||||||||||||||||
| (1)(2) | Revenue (3) | Market Value (4) | Amount (5) | CTC | |||||||||||||||||
| (A) | (B) | (C) | (D) | (E)=(A)-(B)-(C)-(D) | |||||||||||||||||
Customer Transition Charge Customer Class |
|||||||||||||||||||||
Residential Delivery Service Customers |
|||||||||||||||||||||
Single Family Without Space Heat |
8.715 | 3.355 | 3.911 | 0.610 | 0.839 | ||||||||||||||||
Multi Family Without Space Heat |
8.961 | 4.404 | 4.057 | 0.627 | 0.000 | ||||||||||||||||
Single Family With Space Heat |
5.836 | 2.279 | 3.750 | 0.409 | 0.000 | ||||||||||||||||
Multi Family With Space Heat |
6.169 | 2.881 | 3.818 | 0.432 | 0.000 | ||||||||||||||||
Fixture-included Lighting Residential Delivery Service Customers |
8.655 | 9.853 | 3.080 | 0.606 | 0.000 | ||||||||||||||||
Notes:
| (1) | Based on three years of residential historical data ending January 2002 and residential rates in effect beginning October 1, 2001. | |
| (2) | Base rate revenues consist of customer service and energy charges. Base rate revenues do not include facility, meter, or other equipment rentals, franchise fees or other franchise cost additions, fuel adjustment clause charges, decommissioning expense adjustment clause charges, taxes, local government compliance class charges, compensation for energy generated by a person or entity other than ComEd, or Renewable Energy Resources and Coal Technology Development Assistance Charge and Energy Assistance Charge for the Supplemental Low-Income Energy Assistance Fund. | |
| (3) | The amount of revenue that the Company would receive under Rate RCDS — Retail Customer Delivery Service (Rate RCDS) and Rider ISS — Interim Supply Service (Rider ISS) for standard delivery of energy to customers in the CTC Customer Class. | |
| (4) | The Market Value for a CTC Customer Class has the same value as the per kilowatt-hour Load Weighted Average Market Value (LWAMV) as defined in Rider PPO — Power Purchase Option (Market Index) for the applicable delivery service customer class. | |
| (5) | The residential mitigation amount as defined in Rate CTC is 7% of the base rate revenue for the calendar years of 2003 and 2004. |
| Five PUC Commissioners - four Republicans, one Democrat (recently appointed) Five-year staggered terms, expiring March 31 of each year Commissioner Fitzpatrick just appointed as Chairman (term expires 3/31/04), replacing Glen Thomas Governor Rendell (D) appointed Wendell Holland (D) as replacement for Commissioner Wilson (R) 2002 legislation allows no more than three Commissioners from the Governor's party Political & Regulatory Environment - PA |
PECO ENERGY
Restructuring Settlement
This summary of the major elements of the 1998 settlement reflects amendments made in 2000 following announcement of the PECO Unicom merger.
| • | Recovery of $5.26 billion of stranded costs over a 12-year transition period beginning January 1, 1999 and ending December 31, 2010, with a return of 10.75 percent. | |
| • | Rate caps will vary over the transition period. (See Table on Page 2.) | |
| • | On January 1, 1999 PECO unbundled rates into three components: |
| • | a transmission and distribution rate of 2.98 cents per kWh. | ||
| • | a competitive transition charge (CTC) designed to recover the $5.26 billion of stranded costs. Revenue collected through the CTC will be reconciled annually based on actual sales. | ||
| • | a shopping credit initially set at 4.46 cents per kWh on a system-wide basis. |
| • | Authorization for PECO to securitize up to $5 billion of stranded costs. (PECO has securitized fully to its $5B limit.) The intangible transition charges associated with transition bonds terminate no later than December 31, 2010. | |
| • | Flexible pricing, within a specified range, for residential default customers. | |
| • | Customer choice phased in between January 1, 1999 and January 2, 2000. | |
| • | Authorization for PECO to transfer its generation assets to a separate entity. | |
| • | Ability of electric generation suppliers (EGS) to provide metering and billing services to retail customers who have direct access. | |
| • | As required by law, on January 1, 2001 the provider of default service for 20 percent of residential customers was bid competitively. | |
| • | If 35 percent and 50 percent of all customers are not shopping by 2001 and 2003, respectively, a number of customers sufficient to equal those trigger points shall be randomly selected and assigned to licensed suppliers by a PUC-determined process. | |
| • | PLR Requirement: PECO is PLR through 2010. |
PECO ENERGY
Schedule of Rates
Schedule of System Average Rates
¢/kWh
| Credit for | ||||||||||||||||||||||||
| Delivery | Generation | |||||||||||||||||||||||
| T&D Rate | Service | Rate | ||||||||||||||||||||||
| Effective Date | Transmission(a) | Distribution | Cap(b) | CTC/ITC | Only | Cap(c) | ||||||||||||||||||
| (1) | (2) | (3) | (4) | (5) | (6) | |||||||||||||||||||
January 1, 2002 |
0.45 | 2.35 | 2.80 | 2.51 | 4.47 | 6.98 | ||||||||||||||||||
January 1, 2003 |
0.45 | 2.35 | 2.80 | 2.47 | 4.51 | 6.98 | ||||||||||||||||||
January 1, 2004 |
0.45 | 2.41 | 2.86 | 2.43 | 4.55 | 6.98 | ||||||||||||||||||
January 1, 2005 |
0.45 | 2.41 | 2.86 | 2.40 | 4.58 | 6.98 | ||||||||||||||||||
January 1, 2006 |
0.45 | 2.53 | 2.98 | 2.66 | 4.85 | 7.51 | ||||||||||||||||||
January 1, 2007 |
N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
January 1, 2008 |
N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
January 1, 2009 |
N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
January 1, 2010 |
N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
| (a) | Transmission prices listed are for illustration only. The PUC does not regulate rates for transmission Service. | |
| (b) | T&D Rate Cap (column 3) = sum of columns (1)+(2). | |
| (c) | Generation Rate Cap (column 6) = sum of columns (4)+(5). |
Notes:
| • | Average figures for CTC/ITC from 2002-2010 in column 4 are fixed, subject to reconciliation for actual sales levels. | ||
| • | The credit (paid to delivery-service-only-customers) figures in column 5 will be adjusted to reflect changes due to the CTC/ITC reconciliation. | ||
| • | Average transmission and distribution service rates will not exceed the figures in column 3. | ||
| • | The generation portion of bills for customers who remain with regulated PECO generation supply will not, on average, exceed figures in column 6. | ||
| • | Calculation of average rates for 2002: 9.96¢/kWh (existing rate cap) — 1.8 percent reduction = 9.78¢/kWh 9.78¢/kWh = 2.80 (column 3) + 2.51 (column 4) + 4.47 (column 5) |
2
PECO ENERGY
CTC Amortization
Annual Stranded Cost
Amortization and Return(a)
| Revenue, excluding Gross Receipts Tax | ||||||||||||||||||||
| Annual | ||||||||||||||||||||
| Year | Sales | CTC | Total | Return @ 10.75% | Amortization | |||||||||||||||
| MWh | ¢/kWh | ($000) | ($000) | ($000) | ||||||||||||||||
2002 |
34,381,485 | 2.51 | 825,004 | 516,869 | 308,135 | |||||||||||||||
2003 |
34,656,537 | 2.47 | 818,352 | 482,401 | 335,951 | |||||||||||||||
2004 |
34,933,789 | 2.43 | 811,540 | 444,798 | 366,742 | |||||||||||||||
2005 |
35,213,260 | 2.40 | 807,933 | 403,555 | 404,378 | |||||||||||||||
2006 |
35,494,966 | 2.66 | 902,623 | 353,070 | 549,553 | |||||||||||||||
2007 |
35,778,925 | 2.66 | 909,844 | 290,627 | 619,217 | |||||||||||||||
2008 |
36,065,157 | 2.66 | 917,123 | 220,312 | 696,811 | |||||||||||||||
2009 |
36,353,678 | 2.66 | 924,459 | 141,229 | 783,231 | |||||||||||||||
2010 |
36,644,507 | 2.66 | 931,855 | 52,381 | 879,474 | |||||||||||||||
| (a) | Subject to reconciliation of actual sales and collections. Under the settlement, sales are estimated to increase 0.8 percent per year. |
Other Features
| • | The transmission & distribution rate cap of 2.98 cents per kWh includes .01 cent for a sustainable energy and economic development fund during the rate cap period. | |
| • | PECO is permitted to transfer ownership and operation of its generating facilities to a separate corporate entity. The generating facilities will be valued at book value at the time of the transfer. | |
| • | Twenty percent of residential customers will be assigned to a provider of last resort (PLR), other than PECO, on January 1, 2001. The PLR will be selected on the basis of a PUC-approved energy and capacity market price bidding process. PECO-affiliated suppliers will be prohibited from bidding for this block of customers. | |
| • | As of January 1, 2001, PECO (as PLR) will price its service to residential customers within a specified range. | |
| • | A Qualified Rate Order authorizing securitization of up to $4 billion is included (subsequently increased to $5 billion). | |
|
3
Exelon Maturity Schedule — 2003
(Includes issues called to date)
| Refinancing | New Issue | |||||||||||||||||||||||||||||||||||||||||||
| Maturity | Actual Call | Maturity | Pricing | |||||||||||||||||||||||||||||||||||||||||
| Company | Type | Amount ($M) | Coupon | Date | Date | Type | Date | Amount ($M) | Coupon | Date | ||||||||||||||||||||||||||||||||||
Jan |
ComEd | FMB | 200.0 | 7.375 | % | 9/15/02 | ||||||||||||||||||||||||||||||||||||||
| ComEd | FMB | 200.0 | 8.375 | % | 9/15/22 | 9/16/02 | ||||||||||||||||||||||||||||||||||||||
| ComEd | Notes | 200.0 | Variable | 9/30/02 | FMB | 2008 | 350.0 | 3.70 | % | 1/14/03 | ||||||||||||||||||||||||||||||||||
| ComEd | Notes | 100.0 | 9.170 | % | 10/15/02 | FMB | 2033 | 350.0 | 5.875 | % | 1/14/03 | |||||||||||||||||||||||||||||||||
Mar |
ComEd | Trust Pfd Sec | 200.0 | 8.48 | % | 9/30/35 | 3/20/03 | Trust Pfd Sec | 2033 | 200.0 | 6.35 | % | 3/10/03 | |||||||||||||||||||||||||||||||
Mar |
ComEd | FMB | 236.0 | 8.375 | % | 2/15/23 | 3/18/03 | |||||||||||||||||||||||||||||||||||||
| ComEd | FMB | 160.0 | 8.000 | % | 4/15/23 | 4/15/03 | FMB | 2015 | 395.0 | 4.70 | % | 3/31/03 | ||||||||||||||||||||||||||||||||
Apr |
PECO | FMB | 250.0 | 6.625 | % | 3/1/03 | ||||||||||||||||||||||||||||||||||||||
| PECO | FMB | 200.0 | 6.500 | % | 5/1/03 | FMB | 2008 | 450.0 | 3.50 | % | 4/21/03 | |||||||||||||||||||||||||||||||||
May |
ComEd | Pollution | 40.0 | 5.875 | % | 5/15/07 | 5/15/03 | Pollution | 2017 | 40.0 | Variable* | 5/8/03 | ||||||||||||||||||||||||||||||||
| control bonds | Control bonds | |||||||||||||||||||||||||||||||||||||||||||
June |
PECO | Pfd Stock | 50.0 | 7.48 | % | — | 6/11/03 | Trust Pfd Sec | 2033 | 100.0 | 5.75 | % | 6/17/03 | |||||||||||||||||||||||||||||||
| Trust Pfd Sec | 50.0 | 8.00 | % | 6/5/37 | 6/24/03 | |||||||||||||||||||||||||||||||||||||||
| Remaining Maturities | ||||||||||||||||||||||||||||||||||||||||||||
Aug |
ComED | FMB | 100.0 | 6.625 | % | 7/15/03 | (new issue pending) | |||||||||||||||||||||||||||||||||||||
Sep |
ComED | Notes | 250.0 | Variable | 9/30/03 | |||||||||||||||||||||||||||||||||||||||
| * | The initial 35-day pricing rate is 1.13%. |
Exelon Corporation
Transitional Bond Summary
| ($ in millions) | Dec-00 | Dec-01 | Dec-02 | Dec-03 | Dec-04 | Dec-05 | Dec-06 | Dec-07 | Dec-08 | Dec-09 | Dec-10 | |||||||||||||||||||||||||||||||||
ComEd |
||||||||||||||||||||||||||||||||||||||||||||
Year End Principal Balance |
$ | 2,720 | $ | 2,380 | $ | 2,040 | $ | 1,700 | $ | 1,360 | $ | 1,020 | $ | 680 | $ | 340 | $ | — | $ | — | $ | — | ||||||||||||||||||||||
Principal Payments |
$ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | — | $ | — | ||||||||||||||||||||||||
PECO |
||||||||||||||||||||||||||||||||||||||||||||
Year End Principal Balance |
$ | 4,838 | $ | 4,582 | $ | 4,255 | $ | 4,015 | $ | 3,725 | $ | 3,295 | $ | 2,775 | $ | 2,135 | $ | 1,505 | $ | 805 | $ | — | ||||||||||||||||||||||
Principal Payments |
$ | 256 | $ | 327 | $ | 240 | $ | 290 | $ | 430 | $ | 520 | $ | 640 | $ | 630 | $ | 700 | $ | 805 | ||||||||||||||||||||||||
Total |
||||||||||||||||||||||||||||||||||||||||||||
Year End Principal Balance |
$ | 7,558 | $ | 6,962 | $ | 6,295 | $ | 5,715 | $ | 5,085 | $ | 4,315 | $ | 3,455 | $ | 2,475 | $ | 1,505 | $ | 805 | $ | — | ||||||||||||||||||||||
Principal Payments |
$ | 596 | $ | 667 | $ | 580 | $ | 630 | $ | 770 | $ | 860 | $ | 980 | $ | 970 | $ | 700 | $ | 805 | ||||||||||||||||||||||||
| Securities Ratings for Exelon and its Subsidiary Companies |