| Power Marketing Update Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| Safe Harbor Language This presentation includes "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, for example, statements regarding benefits of the proposed merger of Exelon and PSEG, integration plans, and expected synergies, anticipated future financial and operating performance and results, including estimates for growth. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements made herein. A discussion of some of these risks and uncertainties, as well as other risks associated with the proposed merger, is included in the preliminary joint proxy statement/prospectus contained in the Registration Statement on Form S-4 (Registration No. 333-122704) that Exelon has filed with the Securities and Exchange Commission. Additional factors that cause actual results to differ materially from the forward-looking statements made herein are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Outlook and the Challenges in Managing the Business" in Exelon's 2004 Annual Report on Form 10-K. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Neither Exelon nor PSEG undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. |
| Additional Information This presentation is not a solicitation of a proxy from any security holder of Exelon or PSEG. The above-referenced Registration Statement on Form S-4 contains a preliminary joint proxy statement/prospectus and other relevant documents regarding the proposed merger of Exelon and PSEG. WE URGE INVESTORS AND SECURITY HOLDERS TO READ THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE PROPOSED TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT EXELON, PSEG AND THE PROPOSED MERGER. Investors and security holders will be able to obtain these materials (when they are available) and other documents filed with the SEC free of charge at the SEC's website, http://www.sec.gov. In addition, a copy of the definitive joint proxy statement/prospectus (when it becomes available) may be obtained free of charge from Exelon Corporation, Shareholder Services, 10 South Dearborn Street, P.O. Box 805398, Chicago, Illinois 60680-5398, or from Public Service Enterprise Group Incorporated, Investor Relations, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey 07101-1171. The respective directors and executive officers of Exelon and PSEG and other persons may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding Exelon's and PSEG's directors and executive officers and other participants in the solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is available in the preliminary joint proxy statement/prospectus contained in the above-referenced Registration Statement on Form S-4. |
| Introduction and Generation Co. Overview 9:30 - 10:00 John Young, EVP, Finance and Markets Michael Metzner, VP, Investor Relations Power Marketing Overview 10:00 - 10:45 Ian McLean, EVP & President, Power Team Ken Cornew, SVP, Power Transactions Illinois Post-06 Update 10:45 - 11:30 William McNeil, Director, ComEd Regulatory POLR Pricing 11:30 - 12:00 Mike Freeman, Power Transactions Shravan Chopra, Manager, Pricing Break / Lunch 12:00 - 12:30 PJM Overview 12:30 - 2:00 Jack Crowley, Dir, Reg. Affairs, Power Team Penn. Regulatory Update 2:00 - 2:30 Lisa Crutchfield, VP, PECO Regulatory Trading Floor Tour 2:30 - 3:00 Walt Kuhn, Director, Power Transactions AGENDA |
| Key Message: Exelon is well positioned for end of transition periods in Illinois and Pennsylvania Solid Delivery business Exceptional Generation/Power Marketing platform Strong balance sheet and financial discipline Expanding and evolving wholesale markets (PJM) Strong momentum for competitive procurement processes in IL and PA |
| Generation Company Overview John F. Young Executive Vice President, Finance and Markets Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| Revenue $14.5B Net Income $1.86B Assets $42.8B Pennsylvania Utility Illinois Utility Nuclear Fossil Power Team Revenue $7.9B Net Income $673M Capacity 34.7GW Assets $16.4B Revenue $10.3B Net Income $1,128M Customers 5.1M Assets $27.6B Exelon Overview - 2004 |
| Exelon Generation Competitive Energy Supply Business Exelon Nuclear Operates and maintains Exelon's nuclear assets Nuclear Capacity: 17.2 GW Exelon Power Operates and maintains Exelon's fossil and hydro units Fossil Capacity: 7.1 GW Hydro Capacity: 1.6 GW Power Team Optimizes value of energy supply business, manages earnings risk and markets long-term power Contracted Capacity: 8.1 GW Exelon Generation: Premier nuclear operator, achieving top quartile performance during 2000 - 2004 Reliable and commercially responsive fossil operations, significantly improved over previous years Experienced leader in wholesale power marketing and risk management Operational and commercial excellence in the integrated competitive energy supply business Exelon Generation Overview |
| Note: Megawatts based on Exelon Generation's ownership as of 3/29/05 Midwest Owned Generation: Contracted Gen: Total Generation: ComEd PPA Peak Load: 11,679 MW 4,954 MW 16,633 MW 18,375 MW ERCOT/South Owned Generation: Contracted Gen: Total Generation: 2,494 MW 2,875 MW 5,369 MW Mid-Atlantic Owned Generation: Contracted Gen: Total Generation: PECO PPA Peak Load: 11,173 MW 250 MW 11,423 MW 7,820 MW Total Owned Generation: Contracted Gen: Total Generation: 25,888 MW 8,079 MW 33,967 MW Generating Plants % Nuclear 50 Hydro 5 Coal 9 Intermediate 7 Peaker 29 Exelon Energy Delivery Retail Customers 3.7M Electric in Northern Illinois 1.5M Electric and 0.46M Gas in Southeastern Pennsylvania New England Owned Generation: 542 MW Our Regional Positions |
| Our Foundation for Operations A defined management model that drives sustainable performance in Operational excellence Productivity improvement Cost management Depth of talent and experience Structured leadership development and recruiting A bench capable of meeting current and future challenges Rigorous performance management Target top quartile performance Strong track record of delivering on commitments Exelon's management model is the basis for operational discipline, sustainable performance, and the ability to replicate success. |
| Nuclear Performance - Production Consistent growth in generation output Consistently high capacity factors (6 units in top decile) Consistent performance and industry leadership in refueling outage execution (4 of the 5 shortest outages in 2004 - they define top decile) Nuclear production performance is consistently good. MWh (000) |
| Nuclear Performance - Cost Exelon Nuclear is consistently cost competitive Consistent improvement in production cost Exelon's 5 big dual unit sites are 5 of the 6 lowest cost dual unit sites in the U.S. - they define the top decile of performance Exelon Nuclear's low cost generation is a significant competitive advantage. |
| Exelon Power - Improvements Condition-based overhauls are resulting in production improvements and economic gains Production improvements: boiler and turbine overhauls, main steam-line piping replacement, and digital control upgrades Economic gains: plant upgrades to allow new participation in ancillary markets (regulation and black start) Asset Optimization efforts focused on value enhancement Process changes to reduce oil unit start-up time up to 65% and reduce fuel expense Retirement of uneconomic units Improved margins from outage flexibility and improved coordination with Power Team Improved material condition, outage execution, and coordination are optimizing commercial performance. % Available |
| Exelon Generation: Sustained Excellence Operating plans based on business imperatives Continued focus on performance discipline Experienced leader in risk management Deep bench of talent and experience Effectively integrated portfolio strategy Positioned to capitalize on market dynamics |
| Large, low cost, low emissions fleet in competitive markets with strengthening wholesale prices Premier nuclear operator, based on consistent top quartile performance Fuel, dispatch and locational diversity Reliable and commercially responsive fossil operations Experienced leader in wholesale power marketing and risk management Exelon Electric & Gas Will Have an Exceptional Generation Platform |
| Power Marketing Overview Ian P. McLean President, Power Team Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| Nuclear Fossil Hydro Generation Power Team ComEd PECO Wholesale Power & Fuel Markets Affiliates Supply Contracts Power Team manages the interaction between the generation portfolio and the wholesale customers and markets in order to reduce risk and optimize Exelon Generation profitability. Long-Term Contracts Exelon Energy Power Team: Value Added Intermediary |
| Approach to Portfolio Management Over Time Time Before Expiration of Contract % Hedged % Hedged High End of Profit Low End of Profit Load Only Long View Long-Term Portfolio Balancing Portfolio Optimization and Risk Management Operating Profit ($ Million) Develop a set of relevant commercial options to manage portfolio based on realistic market opportunities Evaluate options on following criteria: Gross margins Risk Reduction Credit Implications Commercial Viability Outputs: Near-term portfolio plan Portfolio management parameters, such as strategic gross margin and risk targets Inputs: Current Positions Market Prices, volatilities, correlations Commercial Dynamics: liquidity, active counterparties, products, credit Near-term market perspective Physical Constraints Corporate targets: earnings, risk Timing of portfolio process Update the portfolio plan quarterly Monitor parameters weekly Approach to managing volatility Increase percentage hedged as delivery approaches Have enough supply to meet peak load Cover options created by load obligations so that base load length can be sold Leave some length to spot for operational uncertainties and opportunistic sales Purchase Coal, Oil, and Natural Gas as power is sold Portfolio Management Process |
| Portfolio Management Kenneth W. Cornew Senior Vice President, Power Team Harris Nesbitt Investor Meeting Kennett Square March 31, 2004 |
| Midwest Portfolio Characteristics Indiana Illinois Chicago Portfolio Opportunities / Challenges Recent integration into PJM market has added liquidity to the standard and structured product markets Length from base-load units to participate in higher market prices Load following capability is purchased from third parties and the power pool Lack of liquidity in off-peak market creates a challenge for portfolio management * Assuming $7.50/MMBtu gas price 18,375 PPA Peak Load (MW) 75,293 Annual GWh (2005) Demand - PPA 16,633 Total Capacity $ 90.00 3,629 Peakers* $ 20.00 1,685 Coal $ 4.50 11,319 Nuclear Avg. Variable Cost ($/MWh) Plant 2005 Capacity (MW) |
| Significant Insignificant Portfolio Management in 2005 Includes changes in generation stack due to roll off of PPAs Off-peak length is a major driver of open position Natural gas is purchased for peakers in the summer for high-load days Acquired intermediate products from bilateral market to better match assets and load obligations RES migration assumptions can vary in a range of 2000 MWs; utilize options to cover floating RES risk Portfolio Management in 2006 Biggest drivers of uncertainty are market prices and RES migration. Market prices have been increasing over the last few months particularly in the off peak. Some load-following capability has been acquired from the bilateral market. Commodity Impact Comments Natural Gas Prices Gas is on the margin for some on-peak hours, and we are primarily a base-load generator Oil Prices Oil is not on the margin a significant amount of time and does not drive prices Gas Spark Compared to base-load length, spark length does not significantly drive margins Oil Spark Minimal oil capacity in the portfolio RES = Retail Energy Supplier Midwest: Key Elements Forecast |
| Pennsylvania Maryland New Jersey Delaware Plant 2005 Capacity (MW) Average Variable Cost ($/Mwh) Nuclear 5,890 $5.00 Hydro 1,645 NA Coal 1,420 $34.00 LFG/Cogen/Contract 250 $50.00 Resid Oil and Peakers* 2,218 $65 resid oil / $120 gas Total Capacity 11,423 Demand - PPA Annual (Gwh) (2005) 37,829 PPA Peak Load (MW) 7,820 Portfolio Opportunities / Challenges We operate in a centrally dispatched power pool More liquidity in the PJM region creates more capability to hedge CCGTs are on the margin for a majority of the on-peak hours and many of the summer off-peak hours Length from base load units to participate in higher market prices Capability to follow load is dependent on structured transactions and utilization of the pool * Assuming $7.50/MMBtu gas price LFG = Landfill gas CCGTs = Combined-cycle gas turbines Mid-Atlantic Portfolio Characteristics |
| Significant Insignificant Commodity Impact Comments Natural Gas Prices Gas is increasingly on the margin We have a substantial amount of base-load capacity. Therefore, gas price movements drive the power market and affect our margins. Oil Prices Oil on the margin a significant proportion of the time Gas Spark We have a relatively insignificant amount of gas peakers as compared to base-load length Oil Spark Significant oil-based capacity in the portfolio Portfolio Management 2005 Carrying target length that we will bring into each delivery month for operational risks Acquired intermediate products to complement existing asset portfolio Upside participation and downside protection provided with option strategies in power and fuels markets (WTI and natural gas calls) There is not a lot of load switching to RES due to economics Congestion management strategies are aligned with portfolio management process Portfolio Management 2006 Coal and oil supply are in line with power sales obligations RES = Retail Energy Supplier Mid-Atlantic: Key Elements Forecast |
| ERCOT/South Portfolio Characteristics Plant Capacity Average Variable Cost ($/Mwh) Combined Cycle* 1,975 MW $60.00 Peakers* 3,394 MW $90.00 Total Capacity 5,369 MW * Assuming $7.50/MMBtu gas price Texas Oklahoma Georgia Portfolio Opportunities / Challenges The portfolio assets are in the ERCOT, SPP and SERC regions The combined cycle units are generally hedged forward; remaining length and peaker length used for opportunistic sales ERCOT ISO often runs the peakers for local reliability reasons |
| Significant Insignificant Minimal oil capacity Oil Spark The entire portfolio is spark based; 40% are high efficiency combined-cycle units Gas Spark Oil not on the margin in the region Oil Prices Gas on the margin a significant proportion of the time; however, spark determines regional profit Natural Gas Prices Comments Impact On Our Portfolio Commodity Portfolio Management in 2005 Monitoring summer heat rate movements due to recent retirement and mothball announcements Managing ancillary service option deals creates portfolio optimization opportunity Natural gas is purchased for all forward power sales High heat rate units provide the ability to serve daily call options Portfolio Management in 2006 Market liquidity for Calendar 2006 is picking up, and sparks have traded slightly higher in the last few months Note: Economic Generation only - excludes higher heat rate units ERCOT/South: Key Elements Forecast |
| Gas Price Sensitivity 1 ($ million pre-tax) Gas +20% Gas -20% 2005 $28 ($5) 2006 $58 ($30) Power Price Sensitivity 2 ($ million pre-tax) Power +$1.00 Power -$1.00 2005 $16 ($12) 2006 $38 ($33) Notes: 1. Gas prices were changed with a correlated change in power prices (power prices in the South and East are more significantly affected by gas prices than in the Midwest); coal prices were held constant 2. Power prices were changed; fuel prices were held constant Portfolio Sensitivities for Generation Co. |
| Illinois Post-06 Update William P. McNeil Director, Regulatory Strategies, ComEd Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| Competition Benefiting IL Customers Since the onset of customer choice in 1997, more than 70% of ComEd's biggest customers have chosen alternatives to bundled rates, some saving up to 15% Residential customers saved 20% with a rate reduction, and even more considering a 10-year rate freeze when the CPI increased 20% (current rates lowest since early 1990's) Since 1998, outage frequency is down 44%, duration is down 53% Nuclear capacity factors have increased from 49% to 93% 9,000 megawatts of new competitive power supply brought on line (and not in rate base) |
| Process Moving Forward 12/3/04 ICC staff report to General Assembly endorsed an auction process similar to New Jersey's (best fit with consensus of Procurement Working Group) ComEd made filings at the ICC on February 25 proposing an auction process Details of the filing and case schedule were previewed with all stakeholders including ICC staff Proceeding will likely run through January 2006 Auction has support of a variety of stakeholders Bi-partisan House Committee formed to oversee Post-2006 process (Chairman: George Scully) Will hear testimony from a broad range of stakeholders before determining General Assembly's level of involvement and direction to the ICC A separate filing for delivery rates and new rate design will be made in the 2nd or 3rd quarter of 2005 |
| Illinois Procurement Filing Overview Annual "reverse auction" to procure supply for customers post 2006 Staggered 1, 3 and 5 year contracts for <1 MW customers Staggering creates rate stability for customers 100% of load bid out in year 1; 40% each year thereafter Recent New Jersey BGS auction resulted in wholesale price increase of 18% over prior year due to higher fuel prices, but staggering process reduced impact on customers' electric bills to a 2.8% increase NJ Ratepayer Advocate: "We don't like any increases, but considering what is going on in the market, it is not bad. We were expecting worse." Large customers to be offered annual or hourly price -- depending on whether or not they are subject to competitive declaration 50% load cap for any single supplier Requires mark-to-market collateral posting by suppliers Tariff translates wholesale auction into retail rates by customer class Auction managed by an independent third party and overseen by ICC |
| ComEd Bundled Tariff for Mass Market 2000 2004 2007 Distr 22 22.5 25.7 Trans 3 4 4.25 Line Losses 3 3 3 Energy/Other 49 47.5 45 10 77 77 Assumes increase in wires charges to recover increased investment in transmission and distribution infrastructure and costs. Notes: 2000 and 2004 are representative of unbundling existing tariff. Energy/other includes the cost of energy, capacity, load following, weather, switching and congestion. Mass Market represents residential and small commercial and industrial customer classes (<1 MW). ATC range from $32 to $37 (current forward price = $37); adders from 40% to 50% 78 - 88 ~ 14% rate increase Sales mix: more higher rate sales 49 47.5 45 - 55 |
| ComEd Delivery Service Investments ComEd has made significant investments in Delivery Rate Base and experienced significant increases in costs since the last rate case test year. Note: Financial data is simplified and rounded for illustrative purposes. |
| POLR Pricing Mike Freeman, Power Transactions Shravan Chopra, Manager, Pricing Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| Current Model Utility Genco Customers Hours Genco is sole supplier of customer load through a PPA with ComEd Bundled service for customers >3MW has been declared competitive Genco/ComEd PPA Bundled Rate Customer Load |
| Competitive Procurement Model Competitive Suppliers Utility Genco Customers - - Load up for auction XX% XX% XX% Hours Percentages of System Load Multiple winning bidders would supply customer load in vertical slices (fixed % of hourly energy demand) New rates determined by auction results Clock Auction Rate Options |
| Understanding the Auction: Product Laddering ComEd Suggested Load Auctioned by Term 50% Auction Load Cap allows ExGen to sell slightly less than 50% of its economic generation directly to ComEd; remainder sold through other channels Annual auctions allow for rebalancing position up to the load cap curve Physical asset ownership not required to participate or win in Load Auctions Notes: Unique product term required in 1st Auction to stagger load in future Auctions 1st Auction term begins 1/1/07 with 5 months added to each term to align with the PJM planning year (June 1 - May 31) |
| Fourth annual reverse auction in NJ completed 2/16/05 While the wholesale price of energy increased by 18% over last year's prices, the staggered terms of the auction contracts will result in customers of NJ's largest utility (PSE&G) seeing an annual increase to total bills of 2.8% Only 1/3 of the energy component in the overall bill is put out to bid annually The energy component is approximately half of the overall bill (with the delivery and transmission components comprising the remaining half) Therefore, in any given year, 1/3 of about 50% (or about 1/6) of the total electric bill is out for bid 25 suppliers participated in the reverse auction with 7 winning bidders BGS Auction Summary |
| 2005 BGS Auction Results 2003 Auction 2004 Auction 2005 Auction East 32.1 36.9 45.14 West 23 19 20.77 $32 -$33 $36 -$37 $55.70 (36 Month NJ Avg.) $55.25 (36 Month NJ Avg.) $65.90 (36 Month NJ Avg.) $44 -$46 Transmission Ancillary services Load shape Congestion Risk premium Capacity ~ $23 ~ $19 ~ $21 ATC Forward Energy Cost |
| Full Requirements Contracts Components of a Full Requirements Price A. Underlying Energy - Standard Block Energy Price - Load Shape Price - Volume Risk B. Customer Migration Risk C. Capacity Price D. Ancillaries Price E. Other Risks - Transmission (Congestion) - Credit - Regulatory Components of an Example Full Requirements Contract POLR (Provider of Last Resort) is a Full Requirements Contract Delivering party takes all obligations associated with serving a load at a fixed price Obligations include energy, capacity and ancillary services Delivering party assumes all the risks in the full requirements contract including customer migration risk |
| Risk Management of Full Requirements Forecasted Load and Underlying Energy Curve Actual Load and Underlying Energy Curve Standard Block Products Expected Load Shape Long Short Standard Block Products Actual Load Shape Shorter Longer Forecast............. One of numerous realities........ - Regulatory - Credit - Congestion E. Other Risks D. Ancillaries Price C. Capacity Price B. Customer Migration Risk - Volume Risk - Load Shape Price - Standard Block Energy Price A. Underlying Energy Components of a Full Requirements Price Contractual management Contractual risk management Congestion related options / local supply Buy ancillary services / self supply Buy capacity / self supply Option strategies Option strategies / self supply Buy shaped products / self supply Buy standard blocks / self supply Risk Management Strategy High High Medium Low High High Medium High Low Level of Risk Mitigation |
| PJM Overview Jack Crowley Director, Regulatory Affairs, Power Team Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| PJM is the world's largest competitive wholesale electricity marketplace With the anticipated integration of Dominion Resources, PJM will have a single control area that: Serves 51 million people Has 126,280 megawatts of peak load Has 160,290 megawatts of generating capacity Covers 164,260 square miles of territory in 13 states plus D.C. Exelon will be the largest generator in PJM PJM Marketplace |
| ComEd AEP Dayton APS DPL Dominion MetEd PECO PSEG PPL JCPL AECO PENELEC PEPCO BGE DQE Expanded PJM |
| Energy Markets Locational Marginal Clearing Price Market Day-ahead and Real-Time Energy products Energy Market trading hubs facilitate energy transactions Capacity Markets Daily, monthly, multi-month, and annual capacity markets Ancillary Service Markets PJM procures Spinning, Regulation, Reactive, Black start ancillary service products Bilateral & Self-Supply Options All of the products mentioned above can be bought or sold bilaterally or self-supplied Markets in PJM |
| Independent Market Monitor determined that the PJM markets were competitive in 2004 Transparent market design encourages competitive behavior Average energy prices increased 10.8% in 2004 over 2003 Adjusting for fuel increases, average PJM prices fell 4.2% in 2004 The Independent Market Monitor is concerned with the existing PJM capacity construct and recommends market enhancements State of the PJM Market |
| Single product - Unforced Capacity Credit Fungible across entire market footprint Assumes reliability under all operating conditions No differentiation by generation type or location Procured based on single reserve margin applied to peak load (a vertical demand curve) Daily, Monthly, Multi-Month product Load-Serving Entity (LSE) capacity obligation must be met one day in advance of operating day Existing Capacity Market in PJM |
| Volatile prices - unpredictable behavior Vertical demand curve produces either very low capacity price with small amount of excess supply or very high capacity price with small reductions in available supply Daily market jeopardizes resource adequacy When the new entry capacity price signal is sent, it's too late to build a power plant All capacity resources are not the same Some units critical to reliability (local) can not cover going forward cash costs and are retiring (PSEG units) PJM needs units that can load follow, start multiple times in a day and be on-line in 30 minutes Problems with Current Capacity Construct |
| Centralized commitment four years forward Annual commitment/annual price for capacity Price set by intersection of supply curve and "sloped" demand curve Locational capacity market Operational Reliability Metrics Comprehensive Market Power Mitigation Plan Reliability Backstop Mechanism Bilateral and self-supply contracts accommodated PJM's Proposed Reliability Pricing Model |
| The PJM Market is a well-functioning competitive wholesale market The PJM market facilitates New Jersey/Maryland style load-following auctions Exelon can participate directly in auction or provide underlying supply to other auction participants The PJM market design matches up nicely with Exelon's asset base and risk management skills Proposed capacity construct will enhance price stability and increase overall capacity revenues Impacts/Benefits to Exelon |
| Pennsylvania Regulatory Update Lisa Crutchfield Vice President, PECO Reg. & External Affairs Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |
| 4 2.47 0.46 2.47 4.62 5 2.47 0.46 2.44 4.65 6 2.59 0.46 2.7 4.92 7 2.59 0.46 2.7 5.43 8 2.59 0.46 2.7 5.43 9 2.59 0.46 2.7 5.43 10 2.59 0.46 2.7 5.43 Electric Restructuring & Merger Settlements Energy & Capacity CTC Transmission Distribution 9.96¢ ** 10.02¢ 10.02¢ + 6.6% = E/C (2.7%), CTC (2.6%), D (1.2%) 10.67¢ + 4.8% = E/C 11.18¢ 11.18¢ 11.18¢ 11.18¢ Unit Rates (¢/kWh)* * Rates 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. ** Original settlement total rate cap based on rates at 1/1/97. |
| PECO Bundled Rates PECO's bundled rates (which include charges for transmission & distribution, stranded cost recovery and a capacity and energy charge, or shopping credit) were capped through 2010. The bundled rate is scheduled to increase in 2006 and 2007 with the following estimated impact on Exelon's cash and EPS: Notes: Estimates based on Exelon forecasted energy sales; approximate 35% effective income tax rate assumption. Rates shown here do not reflect annual reconciliations from original settlement for Gross Receipts Tax, Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustment as shown on slide 51; these reconciliations have no material net income or cash impact. * Per table on page 104 of 2004 Form 10-K filing ** Cash impact before principal payments on securitization debt Year T&D Rate Cap Generation Rate Cap Bundled Rate Revenue Stranded Cost Amortization* Net Income Impact EPS Impact EPS Impact Cash Impact** (cents/kWh) (cents/kWh) (cents/kWh) Incremental Impact ( $ in millions) Incremental Impact ( $ in millions) Incremental Impact ( $ in millions) Incremental Impact ( $ in millions) Incremental Impact ( $ in millions) 2005E 2.86 6.98 9.84 - - - - - - 2006E 2.98 7.51 10.49 240 150 60 60 $0.09 160 2007E 2.98 8.01 10.99 180 70 70 70 $0.11 120 |
| Regulatory Issues Exelon/PSEG Merger FERC Transmission Issues Distribution Rate Strategy Compliance with AEPS PA POLR |
| PA PUC POLR Timeline Roundtable Announced Roundtables POLR NOPR Issued Milestones: 3/4 - Motion of Comm. Thomas to initiate Roundtables 3/18 - PUC Issues Secretarial Letter and POLR Issues List Milestones: 4/8 - 1st Roundtable FERC PJM NJ BPU MD PSC CAEM 4/21 - 2nd Roundtable-EDC's PECO Energy PPL First Energy Duquesne Allegheny UGI Milestones: 5/3 - 3rd Roundtable Retail Marketers 5/19 - 4th Roundtable Wholesale Marketers Exelon Generation Other Generators 6/2 - 5th Roundtable Consumer Groups OCA OSBA PAIEUG Penn Futures AFL/CIO Milestones: 12/16 - PUC Issues Proposed Rulemaking 2/26 - Rulemaking Published March '04 April '04 - June '04 Dec '04 - Feb '05 NOPR Rulemaking Process Milestones: 4/26 Submit Comments 5/26 Submit Reply Comments 1-2 years Rulemaking becomes regulation Apr '05 - '06/'07 NOPR: Notice of Proposed Rulemaking |
| Major PA Utilities Post Transition Dates 1/1/05 1/1/07 1/1/09 1/1/10 1/1/11 Duquesne (11%) Penn Power (3%) Allegheny Power (13%) PP&L (24%) PECO Energy (29%) Penelec (11%) MetEd (9%) [Duquesne (11%)] Interim Order allows for "extending" Post- Transition to 1/1/11. Post-Transition for almost 75% of customers does not start until after 1/1/10. With Duquesne Interim POLR Order, Post-Transition customer percentage = 86%. (Includes percentage of customers served in Pennsylvania) |
| Trading Floor Tour Walt Kuhn, Director, Power Transactions Harris Nesbitt Investor Meeting Kennett Square March 31, 2005 |