EX-99.1 2 c97306exv99w1.htm EXHIBIT 99.1 exv99w1
 

Exhibit 99.1

Forward-Looking Statements This presentation includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon Corporation's 2004 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 the Business for each of Exelon, ComEd, PECO and Generation and (b) ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 20, ComEd-Note 15, PECO-Note 14 and Generation-Note 16 and (2) Exelon's Current Report on Form 8-K filed on May 13, 2005 in (a) Exhibit 99.2 Management's Discussion and Analysis of Financial Condition and Results of Operations - Exelon - Business Outlook and the Challenges in Managing the Business and (b) Exhibit 99.3 Financial Statements and Supplementary Data - Exelon Corporation and (3) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Companies). A discussion of risks associated with the proposed merger of Exelon and Public Service Enterprise Group, Incorporated (PSEG) is included in the joint proxy statement/prospectus that Exelon filed with the SEC pursuant to Rule 424(b)(3) on June 3, 2005 (Registration No. 333-122704). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Companies undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

 

John Rowe Chairman, President & Chief Executive Officer Exelon Investor Conference New York City August 5, 2005 Realizing the Promise, Pursuing the Vision

 

Today's Agenda Realizing the Promise, Pursuing the Vision 8:00 a.m.-8:45 a.m. John Rowe - Strategic Overview 8:45 a.m.-9:15 a.m. Jack Skolds - Operations Update 9:15 a.m.-9:45 a.m. Ian McLean - Power Marketing Update 9:45 a.m.-10:00 a.m. Break 10:00 a.m.-10:30 a.m. Betsy Moler - Merger/Federal Regulatory Update 10:30 a.m.-11:00 a.m. Anne Pramaggiore - IL Regulatory/Legislative Update 11:00 a.m.-11:30 a.m. John Young - Financial Overview 11:30 a.m.-12:00 p.m. John Rowe - Wrap-up and Q&A 12:30 p.m.-2:00 p.m. Lunch and informal discussion

 

Realizing the Promise . . . Note: See presentation appendix for reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS 7.5% Annual Growth 2001 2002 2003 2004 We have, in so many ways, begun to realize the promise of the PECO/ComEd Merger

 

Realizing the Promise . . . 30% more valuable than next largest peer 40% after merger with PSEG Data source: Thomson Financial

 

Unicom / PECO Merger Sale of ComEd Fossil Plants Creation of Genco ComEd Joins PJM Exelon today is a product of industry restructuring Exelon By Fostering Competition

 

By Improved Operations ComEd-1997 EXC-2004 ComEd ComEd ComEd ComEd PECO PECO PECO PECO Exceptional nuclear and generation performance Continued improvement in Energy Delivery PECO-1997

 

And by Continued Financial Discipline Controlling costs Cutting our losses Strengthening our Balance Sheet Managing commodity risk

 

To the Benefit of All Stakeholders Shareholders Customers Employees Competitive Exelon

 

Exelon PSEG EE&G U.S. Rank Nuclear MWs 16,751 3,484 20,235 1 Total MWs (1) 34,457 17,018 51,475 1 Elec. Customers 5,200,000 2,100,000 7,300,000 1 Gas Customers 460,000 1,700,000 2,160,000 7 (1) Year-end 2004; Generation numbers include long-term contracts. Note: EE&G MWs do not include effect of any market power mitigation. We're Better Positioned Now than Ever Generation PEG: EXC:

 

(EXELON LOGO)
Appendix:
Reconciliation of GAAP Reported and Adjusted (non-GAAP)
Operating Earnings per Diluted Share
         
2001 GAAP Reported EPS
   $ 2.21  
Cumulative effect of adopting SFAS No. 133
     (0.02 )
Employee severance costs
     0.05  
Litigation reserves
     0.01  
Net loss on investments
     0.01  
CTC prepayment
     (0.01 )
Wholesale rate settlement
     (0.01 )
Settlement of transition bond swap
     —  
2001 Adjusted (non-GAAP) Operating EPS
   $ 2.24  
         
2002 GAAP Reported EPS
   $ 2.22  
Cumulative effect of adopting SFAS No. 141 and No. 142
     0.35  
Gain on sale of investment in AT&T Wireless
     (0.18 )
Employee severance costs
     0.02  
2002 Adjusted (non-GAAP) Operating EPS
   $ 2.41  
         
2003 GAAP Reported EPS
   $ 1.38  
Boston Generating impairment
     0.87  
Charges associated with investment in Sithe Energies, Inc.
     0.27  
Severance
     0.24  
Cumulative effect of adopting SFAS No. 143
     (0.17 )
Property tax accrual reductions
     (0.07 )
Enterprises’ Services goodwill impairment
     0.03  
Enterprises’ impairments due to anticipated sale
     0.03  
March 3 ComEd Settlement Agreement
     0.03  
2003 Adjusted (non-GAAP) Operating EPS
   $ 2.61  
         
2004 GAAP Reported EPS
   $ 2.78  
Charges associated with debt repurchases
     0.12  
Investments in synthetic fuel-producing facilities
     (0.10 )
Severance
     0.07  
Cumulative effect of adopting FIN No. 46-R
     (0.05 )
Settlement associated with the storage of spent nuclear fuel
     (0.04 )
Boston Generating 2004 impact
     (0.03 )
Charges associated with investment in Sithe Energies, Inc.
     0.02  
Costs related to proposed merger with PSEG
     0.01  
2004 Adjusted (non-GAAP) Operating EPS
   $ 2.78  
Note: EPS figures reflect 2-for-1 stock split effective 5/5/04. Three-year 2004/2001 compound annual growth rate (CAGR): $2.78/$2.21 = 7.9% based on GAAP reported results. Three-year 2004/2001 CAGR: $2.78/$2.24 = 7.5% based on adjusted (non-GAAP) operating results.

 

Operations Update John L. Skolds, President, Exelon Energy Delivery and President, Exelon Generation Exelon Investor Conference New York City August 5, 2005

 

Exelon Operations The Management Model is being applied throughout Exelon operations Improving material condition Improving reliability Improving cost management Consistently replicating good results The Model will continue to be applied under the Nuclear Operating Services Agreement and throughout operations post-merger to achieve: Potential merger synergies The benefits of size and scale A high performance, results-oriented culture The Management Model drives strong repeatable results

 

Energy Delivery - Reliability System initiatives are leading to improved reliability Investing in transmission and distribution system reliability Improving material condition of bare steel gas system Fixing top-priority distribution circuits Completing high-impact corrective maintenance Early planning and completion of summer critical work Energy Delivery - Keeping the lights on

 

Energy Delivery - High Performance Building a high-performance operations culture Leveraging the experience of the Nuclear Management Model Focusing on sound fundamentals Improving work management and scheduling processes to reduce cost and improve efficiency and response Preventing human performance errors Improving response during and after storms Energy Delivery - Operational excellence is fundamental

 

Energy Delivery - Becoming Customer-Focused Targeting top quartile in customer satisfaction Performing reliably - fewer outages and faster restoration times Communicating better during storm and non-storm outages Making customer contact a better experience Creating a customer-focused culture "Telling our story" through media outreach Implementing a common customer system Energy Delivery - 1st quartile customer satisfaction in 2007

 

Energy Delivery - Optimizing Spending Reliability improvements achieved while O&M expenses reduced more than 10% since 2001 Future expenses not expected to reach 2002 levels until 2008 Capital strategically invested to support continued system growth and performance improvements Improved long-term planning and work management processes reducing spend variability and enhancing productivity Spending plans coordinated with State and FERC rate strategies to optimize returns 2001 Actual 2002 Actual 2003 Actual 2004 Actual 2005 Forecast 2006 Plan 2007 Plan 2008 Plan East 1568 1488 1455 1391 1400 1450 1460 1484 Energy Delivery - Effective cost management & investment

 

Energy Delivery - Merger Integration What will Exelon Electric & Gas Energy Delivery look like? Central management to ensure alignment and best practices Local utility operations Merger will be transparent to the customer Energy Delivery - Centrally managed with local execution

 

Commercial Availability 80% 85% 90% 95% 100% 2002 2003 2004 June 05 YTD % hours available Exelon Power Performance - Reliability Targeted capital investment and sound operating fundamentals driving fleet efficiency and reliability Market-driven investments in plant improvements that increase unit profitability Material condition improvement resulting in improved unit reliability, heat rate and capacity Capitalizing on market opportunities through improved operating flexibility and market responsiveness Application of Management Model has resulted in improved operations; will provide similar results in the larger PSEG fossil fleet Exelon Power is well positioned to capitalize on market opportunities

 

Nuclear Performance - Production Sustained nuclear production reliability Continued growth in generation output Consistently high capacity factors Continued excellence in refueling outage performance Exelon Nuclear's sustained reliability is a competitive advantage Data sources: Nucleonics Week, Electric Utility Cost Group. Exelon data excludes Salem

 

Nuclear Performance - Cost Exelon capitalizes on its nuclear cost advantage Consistent improvement in production cost Industry leader in production cost by a substantial margin The size & scale of the fleet enables low-cost generation Exelon's low-cost nuclear generation is a competitive advantage Data sources: Electric Utility Cost Group

 

Nuclear Performance - Fuel Costs 2004 2005 2006 2007 2008 2009 2010 Contracted 10700 8991 6923 8456 7342 3629 2520 Flexibilities 1810 3517 1707 1571 186 70 Demand 8437 11587 8472 10027 7528 9196 7393 Uranium market prices have increased, but Exelon is managing its portfolio Reduced uranium consumption by 25% Contracting strategy protects us from increases through 2008 Uranium is a small component of total production cost Expect long-term fundamentals in $20-25 range due to new uranium production Exelon Nuclear is managing fuel costs

 

PSEG/Nuclear Operating Services Agreement Nuclear Operating Services Agreement with Salem/Hope Creek is in place, fully functioning 24 Exelon managers at the site full-time Supported by transition team Augmented by Exelon specialists providing assistance, assessments 2005 priorities defined: sharpened operational focus, equipment reliability, safety conscious work environment, meet financial commitments, successful refueling outages Performance to date: Operations and work management processes improved; increased focus on plant equipment issues Project reviews and reprioritization Cost management processes installed Salem generating well above plan; unit 2 refueling best ever Hope Creek continues to experience equipment issues Support is structured to ensure no distraction from Exelon Nuclear fleet operations

 

Power Marketing Ian P. McLean President, Power Team Exelon Investor Conference New York City August 5, 2005

 

Power Team: Current State of the Portfolio Note: See Appendix for 2004 - 2007 Historical and Forward prices (as of June 29, 2005) We are taking advantage of beneficial market conditions Power prices continue to rise Driven by higher fuel prices and tightening fundamentals Benefits our baseload generation Improvements resulted from PJM expansion (ComEd and AEP control areas) Transmission utilization efficiency Forward market liquidity Heat rates in ERCOT are moving higher Actively involved in and well positioned for market design changes Capacity market reform in PJM Post-2006 load auction in Illinois Nodal market design in ERCOT

 

Portfolio Management Over Time 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, products, credit Near-term market perspective Physical Constraints Corporate targets: earnings, risk Improvements to process Advancing the level of detail in the position reports Extending portfolio process to outer years as market liquidity increases 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

 

Recent RTO Initiatives Initiatives that will support continued reliability Capacity Market Reform in PJM (Reliability Pricing Model-RPM) Final stages of PJM stakeholder development FERC recognizes current capacity construct needs reform Energy and Capacity Market Reform in ERCOT ERCOT is expected to adopt PJM-style Nodal Energy Market Capacity Market reform is generating significant debate PY = PJM Planning Year (June to May) Actual PJM Auction Clearing Prices Range of zonal capacity prices: PJM base case prototype simulation results from 1/26/05

 

Our Regional Positions 10,811 MW 5,435 MW 16,246 MW 8,860 MW Midwest Owned Generation: Contracted Gen: Total Generation: ComEd PPA Avg Load: 2,494 MW 2,875 MW 5,369 MW ERCOT/South Owned Generation: Contracted Gen: Total Generation: 10,866 MW 340 MW 11,206 MW 4,564 MW Mid-Atlantic Owned Generation: Contracted Gen: Total Generation: PECO PPA Avg Load: 24,713 MW 8,650 MW 33,363 MW Total Owned Generation: Contracted Gen: Total Generation: Generating Plants %MW 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 542 MW New England Owned Generation: Note: Megawatts based on Exelon Generation's projected 2006 ownership - as of May 31, 2005 Exelon is positioned as a multi-regional, baseload producer with merchant activity in the South

 

Midwest: Market Dynamics PJM has increased liquidity in NiHub trading Rising fuel prices (Central Appalachian Coal, Natural Gas) Pushing forward PJM NiHub prices higher Capacity prices Cleared $6.91/MW- day for planning year '05/'06 Cal 2006 NiHub On Peak Cal 2006 Central Appalachian Coal (without transportation) Historical Midwest Prices On Peak Off Peak 2002: $26.61 $15.17 2003: $36.96 $18.11 2004: $41.45 $19.75 2005 YTD: $51.63 $29.24 (as of June 29) Market dynamics are driving higher power prices in Northern Illinois July '04 - July '05 Cal 2006 NiHub Off Peak Cal 2006 NYMEX Natural Gas Cal = Calendar year

 

* RES = Retail Energy Supplier Midwest: Portfolio Characteristics Portfolio Management 2005 Balance of year hedged Using power sales and daily power options Coal requirements managed consistently with power sales obligations 2006 RES migration 3,475 MW current planning year Next planning year assumptions +/- 1,500 MW Options are utilized to cover RES* switching risk Acquiring load-following capability from the bilateral market to better match the assets with the load obligation Balanced capacity position across PJM footprint 2007 and beyond Developing strategies for post 2006 load auctions Currently hedging in Cal 2007 and 2008 markets Generation Type 2006 Capacity (MW) Avg. Variable Cost ($/MWHr) Nuclear 10,515 $4.50 Coal 2,073 $20.00 Renewable 54 Peakers 3,604 $100.00 Total Capacity 16,246 PPA Annual Demand (GWHrs) 77,634 PPA Average Load (MW) 8,860 PPA Peak Load (MW) 17,915

 

East: Market Dynamics Cal 2006 West Hub On Peak Cal 2006 Nymex Natural Gas Cal 2006 Nymex Crude Oil August '04 - June '05 Power prices are tracking closely to increasing fuel costs CCGTs* on the margin for majority of on-peak hours Natural gas prices drive power prices Minimal load switching Due to economics Capacity market Remains low through planning year '05/'06 PJM's capacity market design will drive prices * CCGT = Combined Cycle Gas Turbine

 

East: Portfolio Characteristics Generation Type 2006 Capacity (MW) Avg. Variable Cost ($/MWHr) Nuclear 5,766 $5.00 Coal 1,441 $35.00 Hydro 1,618 Renewable 250 Resid Oil, NG and Peakers 2,131 $75 resid oil $120 gas Total Capacity 11,206 PPA Annual Demand 39,983 PPA Average Load (MW) 4,564 PPA Peak Load (MW) 7,981 Portfolio Management 2005 Well positioned for upside participation Option strategies developed in power and fuels markets (Crude oil, residual oil, and natural gas) 2006 Acquiring load-following capability from bilateral market to better match assets with the load obligation Oil and natural gas requirements acquired and shaped to meet our seasonal obligations Active participation in the PJM FTR* auctions Managing congestion risks associated with delivering power to sales and load obligations 2007 and beyond Developing strategies for potential mitigation scenarios associated with the merger Manage remaining baseload position and intermediate needs * FTR = Financial Transmission Right

 

ERCOT/South: Market Dynamics Gas is on the margin Spark spread determines our merchant profitability Recent announcements over two-year horizon Over 7,000 MW of mothballed generation Over 1,500 MW of retiring generation Cal 2006 On Peak Heat Rate: ERCOT North Zone / Houston Ship Channel Natural Gas January '05 - June '05 Expected margin for efficient combined cycle generation has increased 30% in the past quarter

 

ERCOT/South: Portfolio Characteristics Generation Type 2006 Capacity (MW) Avg. Variable Cost ($/MWHr) Combined Cycle 1,975 $65.00 Peakers 3,394 $100.00 Total Capacity 5,369 Portfolio Management 2005 Participated in upward heat rate movement for summer by holding extra length Capture margin when peakers called by ERCOT for local reliability by having physical gas supply available 2006 Active hedging program in 2006; scale selling into higher markets Daily call option sales over the summer will be managed by using a combination of market-based products and our high heat rate units 2007 and beyond Developing hedge strategies in preparation for a nodal market design Markets are being quoted for individual nodal points in the forward market, but a trading hub has yet to develop Note: Position does not include high heat rate units or the call option sales against them

 

Gas Price Sensitivity 1 ($ million pre-tax) Gas +20% Gas -20% Sep to Dec 2005 $7 ($2) Calendar 2006 $56 ($46) Power Price Sensitivity 2 ($ million pre-tax) Power +$1.00 ATC* Power -$1.00 ATC* Sep to Dec 2005 $4 ($3) Calendar 2006 $28 ($27) Notes: 1 Gas prices were changed with a correlated change in power, oil, and coal prices 2 Power prices were changed; fuel prices were held constant Portfolio Sensitivities for Generation Co. * ATC = Around the Clock

 

Appendix Power Marketing

 

Current Market Prices 2004 20051 2006 2007 PRICES (as of June 29) PJM West Hub ATC ($/mwhr) $42.352 $49.02 $53.75 $52.54 PJM NiHUB ATC ($/mwhr) $30.153 $39.82 $42.78 $41.23 NEPOOL MASS HUB ATC ($/mwhr) $52.132 $63.40 $70.32 $68.24 ERCOT North On Peak ($/mwhr) $49.534 $64.85 $73.26 $70.54 Henry Hub Natural Gas ($/mmbtu) $5.854 $7.03 $7.88 $7.53 WTI Crude Oil ($/bbl) $41.485 $54.70 $59.78 $58.44 On Peak Heat Rates (mmbtu/mwhr) (as of June 29) West Hub / Tetco M3 7.57 7.88 7.66 8.02 NiHub / Chicago City Gate 7.18 7.57 7.30 7.46 ERCOT North / Houston Ship Channel 8.68 9.43 9.54 9.58 2005 information is a combination of actual prices through June 29th and market prices for the balance of the year Real Time LMP (Locational Marginal Price) Next day market through April 30, LMP from May to Dec Next day over-the-counter market Average NYMEX settle prices

 

Merger & Federal Regulatory Update Elizabeth A. Moler Executive Vice President, Government and Environmental Affairs and Public Policy Exelon Investor Conference New York City August 5, 2005

 

Status of major filings/approvals: FERC Order Approving Merger Without Hearing Issued 7/1/05 FERC approved our application as proposed with no surprises New merger review provisions in energy bill do not apply DOJ Hart-Scott-Rodino Review Both companies have certified substantial compliance with the second request for information We anticipate the waiting period will expire September 1 DOJ review will continue thereafter, but is not expected to delay closing Pennsylvania Company rebuttal testimony now filed Schedule being revised; hearings now planned for September/October Final decision expected in January, unless we settle earlier New Jersey Schedule being revised; hearings now planned for late November/December Final BPU decision expected in May, unless we settle earlier SEC PUHCA repeal will be effective ~ Feb. 4 No PUHCA order needed unless we close before then Merger Regulatory Update

 

Anticipated Timeline Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Announce Transaction 12/20/04 Shareholder Approvals 7/05 FERC, NJBPU, ICC Regulatory Filings 2/4/05 File Joint Proxy Statement 2/10/05 Work to Secure Regulatory Approvals (FERC, DOJ, ICC*, PAPUC, NJBPU, SEC, and others) Develop Transition Implementation Plans CLOSE TRANSACTION Beginning 1/17/05, Implement Nuclear Operating Services Agreement Q2 2006 * Notice filing only FERC Approval 7/1/05 Respond to DOJ 2nd Request PA PUC Hearings Scheduled NJ BPU Hearings Scheduled NJ BPU Final Decision Expected PA PUC Final Decision Expected

 

Major Provisions of Importance to Exelon: Electricity PUHCA Repeal FERC Authority to Establish Mandatory Electric Reliability Standards FERC Transmission Line Siting Authority Transmission Pricing Incentives Nuclear Sets Stage for New Nuclear Plants Price-Anderson Renewal, Loan Guarantees, Standby Coverage Tax Nuclear Decommissioning Trust Fund Reform Accelerated Depreciation for Transmission, Natural Gas Assets Domenici-Barton Energy Policy Act of 2005

 

Illinois Regulatory/Legislative Update Anne R. Pramaggiore Vice President, Regulatory and Strategic Services, ComEd Exelon Investor Conference New York City August 5, 2005

 

A Retrospective: Milestones August 2004 - August 2005 September 23, 2004: ICC Workshop Procurement Working Group submitted its consensus report to the ICC Staff setting out 18 features of optimal Illinois procurement model December 29, 2004: ICC Staff submitted report to the ICC recommending "Reverse Auction" January-May 2005: House Electric Deregulation Oversight Committee conducted hearings February 2005: ComEd and Ameren filed procurement cases at ICC proposing "Reverse Auction" as procurement method post transition April 2005: Proposed amendment to the Illinois Public Utilities Act to extend the current transition period for two more years failed to pass the House Electric Deregulation Oversight Committee May 17, 2005: Attorney General (AG) filed motion to dismiss ComEd and Ameren "Reverse Auction" cases June 1, 2005: ICC Administrative Law Judge (ALJ) denied AG's motion to dismiss June 8, 2005: Intervenors filed testimony in ComEd procurement case with 11 of 14 parties supporting some form of auction June 22, 2005: AG filed an interlocutory appeal to ICC for reversal of ALJ's ruling July 13, 2005: ICC affirmed ALJ's decision to deny AG's motion to dismiss by 5 - 0 vote Through workshop process and ICC case, strong support for "Reverse Auction" has developed; AG, Citizens Utility Board (CUB), Cook County State's Attorney's Office (CCSAO) remain outlyers Post-2006 Energy Procurement Project

 

June 8th intervenor filing demonstrated strong support for an Illinois "Reverse Auction" 11 of the 14 case participants support "Reverse Auction" or variation thereof Support from retail and wholesale community, large consumers and ICC Staff Opposition from CUB, AG, CCSAO who call for a return to cost-based ratemaking ComEd and Ameren agreed to modifications in rebuttal testimony: 35% load cap 50 MW tranche size Switching between ComEd and Ameren on like products Auction to be held by ComEd and Ameren within first 10 days of September Staff to adopt stronger, more visible role in auction process, enhancing consumer protection features of process Current Status: Procurement Case

 

Looking Forward: Delivery Services Case Late August Filing Vital statistics: Delivery Services Tariff (DST) case driven by infrastructure improvements $1.89B revenue requirement $3.0B gross rate base increase ComEd expects DST overall rate impact to mass market customers to be approximately 5% increase New Business and Capacity Additions Maintain Reliability Improve Reliability General Plant Faciltiy Relocation 2001-2004 47 18 15 13 7 West North

 

Looking Forward: Upcoming Activities ComEd Procurement Case August 19, 2005: ComEd surrebuttal August 29 - September 9, 2005: Hearings October - November 2005: Legislature's veto session November 2005: ALJ proposed order January 24, 2006: ICC final order January - May 2006: Spring legislative session September 2006: First auction is conducted January 2007: New rates go into effect ComEd Delivery Services Case Late August 2005: ComEd files case February - March 2006: Hearings May - June 2006: ALJ proposed order July 2006: ICC final order January 2007: New rates go into effect

 

Financial Overview John F. Young Executive Vice President, Finance and Markets Exelon Investor Conference New York City August 5, 2005

 

Financial Overview 2005 Performance and Outlook 2006 Guidance (stand-alone) Ongoing Earnings Drivers (stand-alone) Deploying our cash Key credit measures Merger Update

 

Year-To-Date Results Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP. First Half 2005 Highlights: Pension funding Sithe exit Favorable weather Strong generation margins Strong first half: 8% growth in operating earnings; GAAP earnings continue to exceed operating earnings

 

Year-To-Date Earnings Drivers Notes: RNF = Revenue net Fuel/Purchased power; PPA = Purchase Power Agreement; SECA = Seams Elimination Charge/Cost Assignment. See presentation appendix for adjusted (non-GAAP) operating EPS reconciliation to GAAP. Higher generation margins drove earnings growth YTD

 

2005 Adjusted (non-GAAP) Operating EPS $3.00-$3.15 $3.30 2005E $0.11 $0.09 $0.13 $0.04 $0.03 ($0.05) ($0.01) ($0.03) $2.78 ($0.02) $2.20 $2.30 $2.40 $2.50 $2.60 $2.70 $2.80 $2.90 $3.00 $3.10 $3.20 2004 Interest O&M Expense/ Other Generation Margins Amort.& Depr./ PECO CTC Amort. Nuclear Refueling Outages Weather Load Growth SECA / Ancillary Services Risks and Opportunities +/- Weather +/- Power Prices +/- Natural Gas Prices +/- Economy YTD Actual Revised Guidance: $3.00 - $3.15 Expected EPS Drivers Note: See presentation appendix for reconciliation to GAAP reported EPS. Favorable weather comparables and generation margins driving earnings growth for balance of year Prior 2005 Guidance was $2.90-$3.10

 

$3.07 $0.17 $0.13 ($0.02) ($0.10) ($0.03) ($0.06) ($0.04) $0.05 $0.01 $3.15 ($0.03) $2.50 $2.60 $2.70 $2.80 $2.90 $3.00 $3.10 $3.20 $3.30 $3.40 $3.50 2006 Estimate Weather PECO Other Volume/ Class Mix GenCo RNF O&M Interest Expense, Net All Other Depr. ComEd Other 2005 Estimate Note: See presentation appendix for reconciliation to GAAP reported EPS. 2006 Adjusted (non-GAAP) Operating EPS - Stand-alone Guidance: $3.00 - $3.30 Expected EPS Drivers $3.00-$3.15 $3.00-$3.30 Higher generation margins and normal load growth, partially offset by higher O&M costs, will continue to drive earnings growth in 2006 Risks and Opportunities +/- Weather +/- Power Prices +/- Natural Gas Prices +/- Economy +/- CTC Reset Prior 2005 Guidance was $2.90-$3.10 Nuclear Refueling Outages

 

2002 2003 2004 2005E 2006E Generation 0.24 0.3 0.33 0.5 0.51 ComEd 0.47 0.45 0.42 0.26 0.27 PECO 0.29 0.25 0.25 0.24 0.22 Composition of Operating Earnings A further shift in relative earnings contribution from Energy Delivery to Generation will occur in 2007 when ComEd becomes a pure wires company and Generation gets a market price for its Midwest production

 

Ongoing Earnings Drivers - Stand-alone Time * Note: See presentation appendix for reconciliation to GAAP reported EPS. Operating Earnings Per Share* 2004 2005E 2006E 2007E $3.15 $3.00 + End of Illinois Transition Period + PECO Generation Rate + Load Growth - Inflation $2.78 $3.30 $3.00 Strong growth expected 2006 - 2007, primarily driven by end of frozen rates in Illinois

 

End of Illinois Transition Period ComEd becomes a pure wires business - Returns determined through traditional regulatory processes - No generation margin - Rate increase expected on delivery services tariff (DST) Exelon Generation gets a market price for all its Midwest production - Approximately 90 TWh nuclear and 10 TWh coal - About 2/3 of which is currently supplied to ComEd at a discount to today's market price Composition of earnings shifts from ComEd to Generation ComEd is willing to work with stakeholders to mitigate the potential customer impacts of transitioning to market prices for generation ComEd Genco Exelon Generation Margin - + + DST + N/A + Net Earnings Impact - + + Net Impact on earnings is expected to be positive for Exelon overall

 

Deploying Our Cash Note: Net Cash from Operations includes cash from normal operations, decommissioning investment, and debt issued for pension funding in 2005. See presentation appendix for definition of Free Cash Flow. 3.8 4.0 (0.8) (0.9) (0.5) (0.5) (0.6) (0.6) (1.0) (1.1) (1.1) (1.1) ($5.0) ($4.0) ($3.0) ($2.0) ($1.0) $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 2005E 2006E $ Billions Net Cash from Operations Dividends Transition Debt Retirements EED CapEx Genco CapEx Nuclear Fuel Aug-04 Projected Free Cash Flow Current Projected Free Cash Flow Our current cash flow forecast reflects increased investments in the core business - mainly on the regulated side (0.1) Corp. CapEx

 

Exelon consolidated: FFO / Interest 7.5x BBB+/Baa2/BBB+ FFO / Debt 39% Debt Ratio 48% Generation: FFO / Interest 13.6x A-/Baa1/BBB+ FFO / Debt 87% Debt Ratio 29% ComEd: FFO / Interest 5.7x A-/A3/A- FFO / Debt 27% Debt Ratio 41%(2) PECO: FFO / Interest 12.6x A-/A2/A FFO / Debt 36% Debt Ratio 45% Projected 2005 Key Credit Measures Exelon stand-alone: Notes: Exelon consolidated, ComEd and PECO metrics exclude securitization debt. See presentation appendix for FFO (Funds from Operations)/Interest and and FFO/Debt reconciliations to GAAP. (1) Senior unsecured ratings for Exelon consolidated and Generation and senior secured ratings for ComEd and PECO (2) Assumes half of ComEd goodwill is written off Exelon's Balance Sheet is strong Credit Ratings(1) S&P/Moody's/Fitch

 

Market Concentration Mitigation 2/4/05 - Filed the merger application with FERC 6/30/05 - FERC approved merger Divestiture Plan Must complete within 12 months Divest a total of 4,000MW fossil fuel facilities Peaking: 1,200MW Mid-Merit: 2,800MW at least 700MW coal-fired "Virtual Divestiture" Transfer control of 2,600MW of baseload nuclear energy Exelon Baseload Load Following Peaking PSEG Baseload Load Following Peaking We believe our FERC-approved mitigation plan fully addresses all market concentration issues

 

Corporate, Business Services 0.28 Trading 0.13 Fossil 0.1 Nuclear 0.29 Nuclear Production 0.2 20% ~$70m 29% ~$100m 28% ~$100m Trading Genco Corp/ Fossil Corporate, Business Services Nuclear Production Improvements Corp/BSC 0.63 Utility 0.37 43% ~$65m T&D Operations 57% ~$85m Corporate, Business Services 13% ~$45m 10% ~$35m Nuclear Cost Reduction Note: Regulated synergies reflect February 4, 2005 testimony. Unregulated: Exelon Generation Regulated: Exelon Energy Delivery (70% = $350 million) (30% = $150 million) $500 Million of Synergies Beyond Year 1 Synergies are mostly unregulated and are backed-up by detailed execution plans

 

Financial Benefits of Merger Stronger platform to achieve consistent earnings growth Improved performance of PSEG nuclear plants - already providing benefit for both companies through Nuclear Operating Services Agreement Synergies of $500 million beyond year 1, mostly in unregulated generation business Earnings accretion for each company's shareholders in year 1 14% higher dividend for Exelon shareholders; PSEG shareholders kept whole Strong balance sheet The merger is operations-driven with strong financial benefits for both Exelon and PSEG shareholders

 

Summary Stand-alone Raising 2005 earnings guidance to reflect strong first half Earnings growth in 2006 driven by higher generation margins, partially offset by higher costs Earnings growth in 2007 driven by end of frozen rates in Illinois Relative earnings contribution shifting from Energy Delivery to Genco Cash flow forecast reflects reinvestment in business - mainly on regulated side Balance sheet strong enough to fund projected investments and continue to grow the dividend Merger FERC-approved market concentration mitigation plan in place Detailed line of sight to synergies History of delivering on commitments

 

Appendix Financial Overview

 

Note: Items may not add due to rounding. Exelon Consolidated GAAP Earnings to Adjusted (non-GAAP) Operating Earnings - YTD (in Millions, except EPS)

 

Consolidated - Key Assumptions

 

Serving ComEd's Mass Market Load Obligation ExGen ComEd Exelon 2160 2820 -3420 -2160 0 -600 The end of frozen rates in Illinois in 2007 means the end of serving ComEd's POLR obligation at a discount to the expected market price Illustration using approximate 2006 data* $ MM pre-tax POLR Mass Market Load Margin: ~60 TWh x ~$(10) variable margin Genco/ ComEd PPA * Assumes 60 TWh ComEd POLR Mass Market Load in 2006, $36 Genco/ComEd PPA price, $57/MWh cost-to-serve and $47/MWh implied average revenue in current bundled tariff. Mass Market represents residential and small commercial and industrial customer classes (<1 MW). Genco Cost to Serve in Market ComEd's Revenue Genco ComEd Exelon Note: POLR = Provider of Last Resort

 

ComEd Delivery Services Investments * Based on actual GAAP data. Reflects 42%/58% debt/equity ratios (including goodwill and transition debt). Assumes 10.5% ROE. Financial data is simplified and rounded for illustrative purposes. Overall requested system Delivery Services Tariff rate increase expected to be about 15%; reflects increases in sales volumes due to load growth and changes in customer class sales mix since 2000 The end of frozen rates in Illinois in 2007 means ComEd can earn a fair return on its distribution investments

 

* Assumes all ComEd customers are served under the current DST rate. Estimated 2004 ComEd Distribution ROE

 

ComEd Transmission Investments Note: Financial data is simplified and rounded for illustrative purposes.

 

ComEd Goodwill Impairment assessment performed at least annually (4th quarter) to determine if estimated fair value (FV) of ComEd supports recorded goodwill Assessment uses discounted cash flow analysis to estimate FV Dependent on variables including interest rates, utility sector market performance, market power prices, post-2006 rate/regulatory structures, operating and cap ex requirements Assessment performed in two steps: Step 1: Compare FV of ComEd to its book value (BV) including goodwill - if FV exceeds BV, no impairment; if not, then go to Step 2 Step 2: Compare FV of goodwill to BV of goodwill - if FV exceeds BV, no impairment; if not, an impairment loss is reported as reduction to goodwill and charged to operating expense Goodwill impairment has no cash flow impact No impairment recorded at ComEd to date, but reasonable possibility goodwill will be impaired going forward Any future impairment charges at ComEd will likely be offset in Exelon's consolidated results Impairment test at Exelon level considers cash flows of entire EED segment, including both ComEd and PECO; PECO has no goodwill and its estimated FV substantially exceeded its BV under the 2004 test Goodwill impairment has no impact on ComEd's ROE rate cap during the transition period through 2006 Impact on ComEd distribution rate case: Goodwill not included in rate base (no return of goodwill)

 

ComEd Balance Sheet/Capital Structure 12/31/03 12/31/03 12/31/04 12/31/04 Projected 12/31/05(1) Projected 12/31/05(1) $ in Billions % of Total Cap. $ in Billions % of Total Cap. $ in Billions % of Total Cap. Goodwill 4.7 - 4.7 - 2.4 - Debt 6.4 50% 4.9 42% 4.6 47% Common Equity 6.3 50% 6.7 58% 5.2 53% Debt(2) 4.8 43%(2) 3.5 34%(2) 3.6 41%(2) Common Equity 6.3 57%(2) 6.7 66%(2) 5.2 59%(2) (1) Assumes a scenario where one-half of goodwill is written off and $0.3B securitization debt matures in 2005. (2) Excludes securitization debt from total debt and total capitalization.

 

Market Concentration Mitigation Release OM1 Release Round II Regulatory Approvals: EE&G Compliance Filing, Buyer Section 203 Filing (estimated to be 3-6 months) 1 month PSA execution Merger Close Round I Bids -3 -2 -1 1 2 3 4 5 6 7 Round II Bids Bidder Conference for interim nuclear auction Conduct interim nuclear auctions Start delivery of interim nuclear auction (ends 5/31/07) Conduct 3-yr nuclear auctions Feb '07 (delivery starts 6/1/07) ...12 13 Planned Timeline Fossil Divestiture Virtual Divestiture Selected Merrill Lynch as advisor DOJ approval pending 2-round RFP process Target purchase and sales agreement (PSA) within 6 months of merger close Interim mitigation in place on merger close Compliance filing on Auction Manager/ Monitor filed 8/1/05 DOJ approval pending In final stages of Auction Manager selection First long-term auction (3-yr product) to be conducted Feb '07 The timing of our mitigation plan is linked to the timing of merger close 1 Offering Memorandum

 

Exelon's outlook for 2005 adjusted (non-GAAP) operating earnings excludes unrealized mark-to-market adjustments from non-trading activities, income resulting from investments in synthetic fuel-producing facilities, the financial impact of the company's investment in Sithe and certain severance costs. The outlook for 2006 adjusted (non-GAAP) operating earnings is Exelon stand-alone and excludes income resulting from investments in synthetic fuel-producing facilities. These estimates do not include any impact of future changes to GAAP. Earnings guidance is based on the assumption of normal weather. 2005/2006 Earnings Guidance

 

Cash Flow Definition We define free cash flow as: Cash from operations (which includes pension contributions and the benefit of synthetic fuel investments), Cash used in investing activities, Debt issued for pension funding, Cash used for transition debt maturities, Common stock dividend payments, Other routine activities (e.g., severance payments, system integration costs, tax effect of discretionary items, etc.) and cash flows from divested operations

 

(EXELON LOGO)
     
FFO Calculation and Ratios
    
Net Income
    
Add back non-cash items:
    
+ Depreciation, amortization (including nucl fuel amortization), AFUDC/Cap Int
   
+ Change in Deferred Taxes
    
+ Gain on Sale and Extraordinary Items
    
+ Trust-Preferred Interest Expense
    
- Transition Bond Principal Paydown
    
 
    
FFO
    
 
    
FFO Interest Coverage
    
 
    
FFO + Adjusted Interest
    
 
    
Adjusted Interest
    
Net Interest Expense (Before AFUDC & Cap Interest)
    
- Trust-Preferred Interest Expense
    
- Transition Bond Interest Expense
    
+ 10% of PV of Operating Leases
    
 
    
Adjusted Interest
    
 
    
FFO Debt Coverage
    
 
    
FFO
    
 
    
Adjusted Average Debt (1)
    
Debt:
    
LTD
    
STD
    
- Transition Bond Principal Balance
    
Add debt equivalents:
    
+ A/R Financing
    
+ PV of Operating Leases
    
 
    
Adjusted Debt
    
(1) Use average of prior year and current year adjusted debt balance
    
 
    
Debt to Total Cap
    
 
    
Adjusted Book Debt
    
 
    
Total Adjusted Capitalization
    
Debt:
    
LTD
    
STD
    
- Transition Bond Principal Balance
    
 
    
Adjusted Book Debt
    
 
    
Capitalization:
    
Total Shareholders’ Equity H Preferred Securities of Subsidiaries
    
Adjusted Book Debt
    
 
    
Total Adjusted Capitalization
    
 
    
Note: FFO and Debt related to non-recourse debt are excluded from the calculations.
    

 

John Rowe Chairman, President & Chief Executive Officer Exelon Investor Conference New York City August 5, 2005 Wrap-up / Q&A

 

Pursuing the Vision Live Up to our Commitments Perform at World-Class Levels Disciplined Financial Management

 

Realizing the Promise, Pursuing the Vision

 

Nuclear Fleet Profile Number of units Net average annual rating 2004* License expiration date Comments Braidwood 2 2,363 2026, 2027 Byron 2 2,336 2024, 2026 Clinton 1 1,030 2026 Dresden 2 1,742 2029, 2031 License renewal approved by NRC 10/04 LaSalle 2 2,288 2022, 2023 Limerick 2 2,309 2024, 2029 Oyster Creek 1 625 2009 License renewal application filed 7/05 ** Peach Bottom 2 2,262 2033, 2034 License renewal approved by NRC 5/03 Quad Cities 2 1,737 2032 License renewal approved by NRC 10/04 TMI-1 1 837 2014 License renewal decision under review Total 17 17,529 * Shown at 100% of capacity ** A 12/04 NRC order permits Oyster Creek to operate beyond its license expiration if the NRC has not completed its renewal application review

 

(EXELON LOGO)
Summary of NuStart Project
July 2005
Background
The NuStart consortium was formed for the purpose of serving as a unified industry entity to respond to a Department of Energy (DOE) solicitation to receive 50/50 cost-share funding for projects designed to address the challenges facing a new nuclear investment. The overall goal of the consortium is to preserve the nuclear option for future investment decisions by reducing the time to market for a new plant. No decision to build a new nuclear plant has been made by NuStart or any of its members at this time.
Participants in NuStart Consortium:
  1.   Constellation
 
  2.   Duke Energy
 
  3.   EDF International North America
 
  4.   Entergy
 
  5.   Exelon
 
  6.   Florida Power and Light
 
  7.   Progress Energy
 
  8.   Southern Company
 
  9.   Tennessee Valley Authority (TVA)
 
  10.   Westinghouse
 
  11.   General Electric
Project Objectives:
  •   Demonstrate new licensing process by preparing and submitting Combined Operating License (COL) applications to the Nuclear Regulatory Commission for review and approval.
 
  •   Complete the design engineering work for the selected advanced reactor technologies, the Westinghouse Advanced Passive (AP) 1000 and the General Electric Economic Simplified Boiling Water Reactor (ESBWR).
Project Milestones:
         
•
  NuStart Formed   March 2004
•
  Proposal submitted to DOE   April 2004
•
  Notified by DOE as award candidate   November 2004
•
  Cooperative Agreement finalized with DOE   May 2005
•
  Select sites for subject of COLs   September 2005
•
  Submit Design Certification application for ESBWR   September 2005
•
  Receive Design Certification for AP1000   December 2005
•
  Submit COL applications   2007/08
•
  Receive approved COLs from NRC   2010/11
Project Funding:
  •   Eight of the nine power companies (excluding TVA) will be providing approximately $7M each for a total of $56M
 
  •   TVA to provide $.6M of in-kind services
 
  •   General Electric and Westinghouse will collectively provide $204M
 
  •   Total industry contribution: $260M
 
  •   DOE matching funds: $260M
 
  •   Total project cost: $520M

 

ComEd Restructuring Legislation
Enacted Dec. 1997
Rate Reductions
         
•
  Residential -   15% effective 1/1/98 ~ $400 million total
 
      5% effective 10/1/2001 ~ $100 million total
     Direct Access Phase-In Schedule
         
•
  Residential    
 
  5/1/2002   100% of residential customers have supplier choice.
•   Commercial and Industrial, including 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.

1

 

•   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 reorganize, 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); and accelerate depreciation or amortization of 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.

2

 

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; a goodwill impairment would have no impact on the ROE rate cap during the transition period ComEd ROE Cap - Earnings Sharing Formula

 

May 25, 2005
Supersedes Charges Filed February 1, 2005
Attachment B1 R: p 1 of 6
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 2005 — May 2006)
(All units are in cents per kilowatt-hour)
                                                         
                            2005           2006    
    Base Rate Revenue   Delivery Service           Mitigation   June 2005 - December 31, 2005   Mitigation   January 1, 2006 - May, 2006
    (1)(2)   Revenue (3)   Market Value (4)   Amount (5)   CTC   Amount (6)   CTC
    (A)   (B)   (C)   (D)   (E) = (A) - (B) - (C) - (D)   (F)   (G) = (A) - (B) - (C) - (F)
Customer Transition Charge Customer Class
                                                        
 
                                                        
Residential Delivery Service Customers
                                                        
Single Family Without Space Heat
     8.715       3.470       4.272       0.697       0.276       0.872       0.101  
Multi Family Without Space Heat
     8.961       4.546       4.411       0.717       0.000       0.896       0.000  
Single Family With Space Heat
     5.836       2.433       4.232       0.467       0.000       0.584       0.000  
Multi Family With Space Heat
     6.169       2.994       4.346       0.494       0.000       0.617       0.000  
Fixture-included Lighting Residential Delivery Service Customers
     8.655       10.003       3.422       0.692       0.000       0.866       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 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 TS — Transmission Services (Rider TS) 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 8% of the base rate revenue for the calendar year 2005.
 
(6)   The residential mitigation amount as defined in Rate CTC is 10% of the base rate revenue for the calendar year 2006.

 

 

May 25, 2005
Supersedes Charges Filed February 1, 2005
Attachment B1: p 1 of 9
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 2005 — May 2006)
(All units are in cents per kilowatt-hour)
                                                         
                            2005           2006    
    Base Rate Revenue   Delivery Service           Mitigation   June 2005 - December 31, 2005   Mitigation   January 1, 2006 - May 2006
    (l)(2)   Revenue (1)(3)   Market Value (4)   Amount (5)   CTC (6)(7)   Amount (8)   CTC (6, 7)
    (A)   (B)   (C)   (D)   (E) = (A)-(B)-(C)-(D)   (F)   (G) = (A)-(B)-(C)-(F)
Customer Transition Charge Customer Class
                                                        
 
                                                        
Nonresidential Delivery Service Customers
                                                        
With Only Watt-hour Only Meters
     11.258       3.897       4.435       1.238       1.688       1.351       1.575  
0 kW to and including 25 kW Demand
     9.288       2.307       4.350       1.022       1.609       1.115       1.516  
Over 25 kW to and including 100 kW Demand
     8.344       2.062       4.372       0.918       0.992       1.001       0.909  
Over 100 kW to and including 400 kW Demand
     7.428       1.680       4.338       0.817       0.593       0.900       0.510  
Fixture-included Lighting Nonresidential Delivery Service Customers
     13.554       10.003       3.401       1.491       0.000       1.626       0.000  
Street Lighting Delivery Service Customers — Dusk to Dawn
     3.852       2.052       3.388       0.600       0.000       0.900       0.000  
Street Lighting Delivery Service Customers — All Other Lighting
     7.172       2.021       3.934       0.789       0.428       0.900       0.317  
Railroad Delivery Service Customers (9)
                                                        
Pumping Delivery Service Customers
     6.465       1.625       4.054       0.711       0.075       0.900       0.000  
Notes:
(1)   Transfer from Column (H) and Column (M) of Determination of Customer Transition Charge, on Pages 2 to 9 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 TS — Transmission Services (Rider TS) 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 0.6 cents per kilowatt-hour or 11% of the base rate revenue for the calendar year 2005.
 
(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).
 
(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)   The mitigation amount as defined in Rate CTC is the greater of 0.9 cents per kilowatt-hour or 12% of the base rate revenue for the calendar year of 2005.
(9) There are two customers in the Railroad class and each customer will have a Customer-specific CTC.

 

 

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.·

1

 

PECO ENERGY
Schedule of Rates
Schedule of System Average Rates
¢/kWh
                                                 
                                    Credit for    
                                    Delivery   Generation
                    T&D Rate           Service   Rate
    Transmission(a)   Distribution   Cap(b)   CTC/ITC   Only   Cap(c)
Effective Date   (1)   (2)   (3)   (4)   (5)   (6)
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  
Note: Original settlement rates.
 
(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 2004-2010 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 2004: 9.84¢/kWh = 2.86 (column 3) + 2.43 (column 4) + 4.55 (column 5)

2

 

PECO ENERGY
CTC Amortization
Annual Stranded Cost
Amortization and Return (a)
                                         
    Annual           Revenue, excluding Gross Receipts Tax
    Sales   CTC   Total   Return @ 10.75%   Amortization
Year   MWh   ¢/kWh   ($000)   ($000)   ($000)
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.
 
•   Market share thresholds were established as of January 1, 2001 to promote competition. The PLR would be selected on the basis of a PUC-approved energy and capacity market price bidding process. PECO-affiliated suppliers would 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

 

2004 2.47 0.46 2.47 4.62 2005 2.47 0.46 2.44 4.65 2006 2.59 0.46 2.7 4.92 2007 2.59 0.46 2.7 5.43 2008 2.59 0.46 2.7 5.43 2009 2.59 0.46 2.7 5.43 2010 2.59 0.46 2.7 5.43 PECO 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. July 2005

 

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 reflect latest annual reconciliations from original settlement for Gross Receipts Tax, Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustments; 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 2.93 7.09 10.02 - - - - - - 2006E 3.05 7.62 10.67 240 150 60 60 $0.09 160 2007E 3.05 8.13 11.18 190 70 80 80 $0.12 130 July 2005

 

Securities Ratings for Exelon and its Subsidiary Companies August 1, 2005 (1) On December 20, 2004, Standard and Poor's placed the ratings of Exelon and its subsidiaries on credit watch with negative implications in response to the announced merger between Exelon & PSEG.

 

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  
(EXELON LOGO)
August 2005

 

 

Exelon Corporation (Holding Co.)
Long-Term Debt Outstanding By Issue
As of June 30, 2005
                                                 
    Interest   Date   Maturity   Debt   Current   Long-Term
Series   Rate   Issued   Date   Outstanding   Portion   Debt
Senior Notes — Exelon Corporation
                                                
2005 Senior Notes
     4.45 %     06/09/05       06/15/10     $ 400,000,000     $ 0     $ 400,000,000  
2005 Senior Notes
     4.90 %     06/09/05       06/15/15     $ 800,000,000     $ 0     $ 800,000,000  
2005 Senior Notes
     5.625 %     06/09/05       06/15/35     $ 500,000,000     $ 0     $ 500,000,000  
2001 Senior Notes
     6.75 %     05/08/01       05/01/11     $ 500,000,000     $ 0     $ 500,000,000  
 
                                                
 
Total Senior Notes — Exelon Corporation
                           $ 2,200,000,000     $ 0     $ 2,200,000,000  
 
                                                
 
                                                
Total Exelon Corporation Long-Term Debt
                           $ 2,200,000,000     $ 0     $ 2,200,000,000  
 
                                                

 

 

ComEd
Long-Term Debt Outstanding By Issue
As of June 30, 2005
                                                 
    Interest   Date   Maturity   Debt   Current   Long-Term
Series   Rate   Issued   Date   Outstanding   Portion   Debt
First Mortgage Bonds
                                                
93
     7.000 %     07/01/93       07/01/05     $ 162,910,000     $ 162,910,000     $ 0  
76
     8.250 %     10/01/91       10/01/06       95,000,000       0       95,000,000  
78
     8.375 %     10/15/91       10/15/06       31,021,000       0       31,021,000  
Pollution Control-1996A
     4.400 %     06/27/96       12/01/06       110,000,000       0       110,000,000  
Pollution Control-1996B
     4.400 %     06/27/96       12/01/06       89,400,000       0       89,400,000  
99
     3.700 %     01/22/03       02/01/08       295,000,000       0       295,000,000  
83
     8.000 %     05/15/92       05/15/08       120,000,000       0       120,000,000  
Pollution Control-1994B
     5.700 %     01/15/94       01/15/09       15,900,000       0       15,900,000  
102
     4.740 %     08/25/03       08/15/10       212,000,000       0       212,000,000  
98
     6.150 %     03/13/02       03/15/12       450,000,000       0       450,000,000  
92
     7.625 %     04/15/93       04/15/13       125,000,000       0       125,000,000  
IL Dev. Fin. Authority - 2002 A
   Variable     06/04/02       04/15/13       100,000,000       0       100,000,000  
94
     7.500 %     07/01/93       07/01/13       127,000,000       0       127,000,000  
IL Dev. Fin. Authority - 2003 D
   Variable     12/23/03       01/15/14       19,975,000       0       19,975,000  
Pollution Control-1994C
     5.850 %     01/15/94       01/15/14       17,000,000       0       17,000,000  
IL Fin. Authority - 2005
   Variable     03/17/05       03/01/17       91,000,000       0       91,000,000  
101
     4.700 %     04/07/03       04/15/15       260,000,000       0       260,000,000  
IL Dev. Fin. Authority - 2003 A
   Variable     05/08/03       05/15/17       40,000,000       0       40,000,000  
IL Dev. Fin. Authority - 2003 B
   Variable     09/24/03       11/01/19       42,200,000       0       42,200,000  
IL Dev. Fin. Authority - 2003 C
   Variable     11/19/03       03/01/20       50,000,000       0       50,000,000  
100
     5.875 %     01/22/03       02/01/33       253,600,000       0       253,600,000  
 
                                                
Total First Mortgage Bonds
                           $ 2,707,006,000     $ 162,910,000     $ 2,544,096,000  
 
                                                
 
                                                
Sinking Fund Debentures
                                                
Sinking Fund Debenture
     3.875 %     01/01/58       01/01/08       4,000,000       1,000,000       3,000,000  
Sinking Fund Debenture
     4.625 %     01/01/59       01/01/09       2,000,000       400,000       1,600,000  
Sinking Fund Debenture
     4.750 %     12/01/61       12/01/11       5,600,000       800,000       4,800,000  
 
                                                
Total Sinking Fund Debentures
                           $ 11,600,000     $ 2,200,000     $ 9,400,000  
 
                                                
 
                                                
Notes Payable
                                                
Notes
     6.400 %     10/15/93       10/15/05       107,024,000       107,024,000       0  
Notes
     7.625 %     01/09/97       01/15/07       145,000,000       0       145,000,000  
Notes
     6.950 %     07/16/98       07/15/18       140,000,000       0       140,000,000  
 
                                                
Total Notes Payable
                             392,024,000       107,024,000       285,000,000  
 
                                                
 
                                                
Total Long-Term Debt
                           $ 3,110,630,000                  
 
                                                
 
                                                
Long-Term Debt to Financing Trusts
                                                
 
                                                
Class A-6 Transitional Funding Trust Notes, Series 1998
     5.630 %     12/16/98       06/25/07       639,998,590       299,998,590       340,000,000  
Class A-7 Transitional Funding Trust Notes, Series 1998
     5.740 %     12/16/98       12/25/08       510,000,000       0       510,000,000  
Subordinated Debentures
     6.350 %     03/17/03       03/15/33       206,186,000       0       206,186,000  
Subordinated Debentures
     8.500 %     01/24/97       01/15/27       154,640,000       0       154,640,000  
 
                                                
 
                                                
Total Long-Term Debt to Financing Trusts
                           $ 1,510,824,590     $ 299,998,590     $ 1,210,826,000  
 
                                                

 

 

PECO Energy
Long-Term Debt Outstanding By Issue
As of June 30, 2005
                                                 
    Interest   Issue   Maturity   Debt   Current   Long-Term
Series   Rate   Date   Date   Outstanding   Portion   Debt
First and Refunding Mortgage Bonds
                                                
FMB
     5.90 %     04/23/04       05/01/34     $ 75,000,000     $ 0     $ 75,000,000  
FMB
     3.50 %     04/28/03       05/01/08       450,000,000       0       450,000,000  
FMB
     5.95 %     11/01/01       11/01/11       250,000,000       0       250,000,000  
FMB
     4.75 %     9/23/02       10/1/12       225,000,000       0       225,000,000  
 
                                                
 
                                                
Total First Mortgage Bonds
                           $ 1,000,000,000     $ 0     $ 1,000,000,000  
 
                                                
 
                                                
Mortgage—Backed Pollution Control Notes
                                                
Delaware Co. 1988 Ser. A
   var. rate     04/01/93       12/01/12       50,000,000       0       50,000,000  
Delaware Co. 1988 Ser. B
   var. rate     04/01/93       12/01/12       50,000,000       0       50,000,000  
Delaware Co. 1988 Ser. C
   var. rate     04/01/93       12/01/12       50,000,000       0       50,000,000  
Salem Co. 1988 Ser. A
   var. rate     04/01/93       12/01/12       4,200,000       0       4,200,000  
 
                                                
 
                                                
Total Mortgage-Backed Pollution Control Notes
                           $ 154,200,000     $ 0     $ 154,200,000  
 
                                                
 
                                                
Notes Payable — Accts. Rec. Agreement
   variable             11/14/05       37,586,111       37,586,111       0  
 
                                                
 
                                                
Total Long-Term Debt
                           $ 1,191,786,111                  
 
                                                
 
                                                
Long-Term Debt to PETT* and Other Financing Trusts
                                                
1999 A-6
     6.0500 %     03/26/99       03/01/07       796,791,475       210,805,100       585,986,375  
1999 A-7
     6.1300 %     03/26/99       09/01/08       896,653,425       0       896,653,425  
2000 A-3
     7.6250 %     05/02/00       03/01/09       398,838,452       0       398,838,452  
2000 A-4
     7.6500 %     05/02/00       09/01/09       351,161,548       0       351,161,548  
2001 A-1
     6.5200 %     03/01/01       09/01/10       805,460,000       0       805,460,000  
PECO Energy Capital Trust III Series D
     7.38 %     04/06/98       04/06/28       81,325,825       0       81,325,825  
PECO Energy Capital Trust IV
     5.75 %     06/24/03       06/15/33       103,092,784       0       103,092,784  
 
                                                
 
                                                
Total Long-Term Debt to PETT and Other Financing Trusts
                           $ 3,433,323,509     $ 210,805,100     $ 3,222,518,409  
 
                                                
 
*   PETT — PECO Energy Transition Trust

 

 

Exelon Generation
Long-Term Debt Outstanding By Issue
As of June 30, 2005
                                         
    Interest     Issue   Maturity   Debt     Current     Long-Term  
Series   Rate     Date   Date   Outstanding     Portion     Debt  
 
Senior Notes
                                        
 
                                        
2001 Senior Unsecured Notes
     6.95 %   6/14/01   6/15/11   $ 700,000,000     $ 0     $ 700,000,000  
2003 Senior Unsecured Notes
     5.35 %   12/16/03   1/15/14     500,000,000       0       500,000,000  
 
                                  
 
                                        
Total Senior Unsecured Notes
                   $ 1,200,000,000     $ 0     $ 1,200,000,000  
 
                                  
 
                                        
Unsecured Pollution Control Notes
                                        
 
                                        
Montgomery Co. 2001 Ser. B
   var. rate   9/5/01   10/1/30     68,795,000       0       68,795,000  
Delaware Co. 2001 Ser. A
   var. rate   4/25/01   4/1/21     39,235,000       0       39,235,000  
Montgomery Co. 2001 Ser. A
   var. rate   4/25/01   10/1/34     13,150,000       0       13,150,000  
Delaware Co. 1993 Ser. A
   var. rate   8/24/93   8/1/16     24,125,000       0       24,125,000  
Salem Co. 1993 Ser. A
   var. rate   9/9/93   3/1/25     23,000,000       0       23,000,000  
Montgomery Co. 1994 Ser. A
   var. rate   2/14/95   6/1/29     82,560,000       0       82,560,000  
Montgomery Co. 1994 Ser. B
   var. rate   7/2/95   6/1/29     13,340,000       0       13,340,000  
York County 1993 Ser. A
   var. rate   8/24/93   8/1/16     18,440,000       0       18,440,000  
Montgomery Co. 1996 Ser. A
   var. rate   3/27/96   3/1/34     34,000,000       0       34,000,000  
Montgomery Co. 2002 Ser. A
   var. rate   7/24/02   12/1/29     29,530,000       0       29,530,000  
Indiana Co. 2003 A
   var. rate   6/3/03   6/1/27     17,240,000       0       17,240,000  
Delaware Co. 1999 Ser. A
   var. rate   10/01/04   04/01/21     50,765,000       0       50,765,000  
Montgomery Co. 1999 Ser. A
   var. rate   10/01/04   10/01/30     91,775,000       0       91,775,000  
Montgomery Co. 1999 Ser. B
   var. rate   10/01/04   10/01/34     13,880,000       0       13,880,000  
 
                                  
 
                                        
Total Unsecured Pollution Control Notes
                   $ 519,835,000     $ 0     $ 519,835,000  
 
                                  
 
                                        
Notes Payable and Other
                                        
 
                                        
Notes Payable
     6.33 %       8/8/09     49,304,753       9,860,951       39,443,803  
Capital Lease Obligations
                     46,581,169       2,114,924       44,466,245  
 
                                        
Total Notes Payable and Other
                   $ 95,885,922     $ 11,975,875     $ 83,910,048  
 
                                  
 
                                        
Total Exelon Generation Long-Term Debt
                   $ 1,815,720,922     $ 11,975,875     $ 1,803,745,048