Exhibit 99.3
Reconciliation of GAAP Reported and Operating Earnings per Share
2000 Reported EPS | $ | 2.87 | ||
| Change in common shares | (1.06 | ) | ||
| Extraordinary items | (0.07 | ) | ||
| Cumulative effect of accounting change | 0.01 | |||
| Unicom pre-merger results | 1.58 | |||
| Merger-related costs | 0.68 | |||
| Pro forma merger accounting adjustments | (0.15 | ) | ||
2000 Pro Forma Operating EPS | $ | 3.86 |
2001 Reported EPS | $ | 4.43 | ||
| Cumulative effect of adopting SFAS 133 | (0.04 | ) | ||
| Employee severance cost | 0.09 | |||
| Litigation reserves | 0.03 | |||
| Net loss on investments | 0.02 | |||
| CTC prepayment | (0.02 | ) | ||
| Wholesale rate settlement | (0.01 | ) | ||
| Settlement of transition bond swap | (0.01 | ) | ||
2001 Pro Forma Operating EPS | $ | 4.49 |
2002 Reported EPS | $ | 4.44 | ||
| Transition loss on implementation of FAS 141 and 142 | 0.71 | |||
| Gain on sale of AT&T Wireless | (0.36 | ) | ||
| Employee severance costs | 0.04 | |||
2002 Pro Forma Operating EPS | $ | 4.83 |
Exelon Energy Delivery
Consolidated Statement of Income
(unaudited)
(in millions, except per share data)
| Six Months Ended June 30, 2003 | |||||||||||||
| Pro Forma | |||||||||||||
| GAAP (a) | Adjustments | Pro Forma | |||||||||||
Operating revenues | $ | 4,964 | $ | — | $ | 4,964 | |||||||
Operating expenses | |||||||||||||
| Purchased power | 1,918 | — | 1,918 | ||||||||||
| Fuel | 257 | — | 257 | ||||||||||
| Operating and maintenance | 744 | (41 | )(b) | 703 | |||||||||
| Depreciation and amortization | 427 | — | 427 | ||||||||||
| Taxes other than income | 258 | — | 258 | ||||||||||
Total operating expenses | 3,604 | (41 | ) | 3,563 | |||||||||
Operating income | 1,360 | 41 | 1,401 | ||||||||||
Other income and deductions | |||||||||||||
| Interest expense | (383 | ) | — | (383 | ) | ||||||||
| Distributions on preferred securities of subsidiaries | (22 | ) | — | (22 | ) | ||||||||
| Equity in earnings of unconsolidated affiliates | — | — | — | ||||||||||
| Other, net | 43 | (12 | )(b) | 31 | |||||||||
Total other income and deductions | (362 | ) | (12 | ) | (374 | ) | |||||||
Income before income taxes and cumulative effect of changes in accounting principles | 998 | 29 | 1,027 | ||||||||||
Income taxes | 382 | 12 | 394 | ||||||||||
Income before cumulative effect of changes in accounting principles | 616 | 17 | 633 | ||||||||||
Cumulative effect of changes in accounting principles, net of income taxes | 5 | (5 | )(c) | — | |||||||||
Net income | $ | 621 | $ | 12 | $ | 633 | |||||||
Effect of pro forma adjustments on earnings per | |||||
Exelon Corporation’s average diluted common share recorded in | |||||
accordance with GAAP: | |||||
| March 3 ComEd Settlement Agreement | $ | (0.05 | ) | ||
| Cumulative effect of adopting SFAS No. 143 | (0.02 | ) | |||
| Total pro forma adjustments | $ | (0.07 | ) | ||
| (a) | Results reported in accordance with accounting principles generally accepted in the United States (GAAP). | |
| (b) | Pro forma adjustment for the March 3 ComEd Settlement Agreement. | |
| (c) | Pro forma adjustment for the cumulative effect of adopting SFAS No. 143. |
Exelon Generation Company, LLC
Consolidated Statement of Income
(unaudited)
(in millions, except per share data)
| Six Months Ended June 30, 2003 | |||||||||||||
| Pro Forma | |||||||||||||
| GAAP (a) | Adjustments | Pro Forma | |||||||||||
Operating revenues | $ | 3,765 | $ | — | $ | 3,765 | |||||||
Operating expenses | |||||||||||||
| Purchased power | 1,642 | — | 1,642 | ||||||||||
| Fuel | 706 | — | 706 | ||||||||||
| Operating and maintenance | 943 | — | 943 | ||||||||||
| Depreciation and amortization | 91 | — | 91 | ||||||||||
| Taxes other than income | 88 | — | 88 | ||||||||||
Total operating expenses | 3,470 | — | 3,470 | ||||||||||
Operating income | 295 | — | 295 | ||||||||||
Other income and deductions | |||||||||||||
| Interest expense | (38 | ) | — | (38 | ) | ||||||||
| Distributions on preferred securities of subsidiaries | — | — | — | ||||||||||
| Equity in earnings of unconsolidated affiliates | 37 | — | 37 | ||||||||||
| Other, net | (134 | ) | 200 | (b) | 66 | ||||||||
Total other income and deductions | (135 | ) | 200 | 65 | |||||||||
Income before income taxes and cumulative effect of changes in accounting principles | 160 | 200 | 360 | ||||||||||
Income taxes | 71 | 70 | 141 | ||||||||||
Income before cumulative effect of changes in accounting principles | 89 | 130 | 219 | ||||||||||
Cumulative effect of changes in accounting principles, net of income taxes | 108 | (108 | )(c) | — | |||||||||
| �� | |||||||||||||
Net income | $ | 197 | $ | 22 | $ | 219 | |||||||
Effect of pro forma adjustments on earnings per | |||||
Exelon Corporation’s average diluted common share recorded in | |||||
accordance with GAAP: | |||||
| Impairment of Exelon’s investment in Sithe Energies, Inc. | $ | (0.40 | ) | ||
| Cumulative effect of adopting SFAS No. 143 | 0.33 | ||||
| Total pro forma adjustments | $ | (0.07 | ) | ||
| (a) | Results reported in accordance with accounting principles generally accepted in the United States (GAAP). | |
| (b) | Pro forma adjustment for the impairment of Exelon’s investment in Sithe Energies, Inc. | |
| (c) | Pro forma adjustment for the cumulative effect of adopting SFAS No. 143. |
| Exelon New England Plants June 10, 2003 Status Capacity (MWs) Fuel Heat Rate (Btu/kWh) 2003 Projected Capacity Factor Fore River (Base-load) Construction 807 Gas/Oil 6,850 > 50% Total Merchant Under Constr. 807 Framingham 1 (Peaking) Operating 13 Oil 13,500 < 5% Framingham 2 (Peaking) Operating 11 Oil 13,500 < 5% Framingham 3 (Peaking) Operating 13 Oil 13,500 < 5% Mystic 4 (Intermediate) Operating 135 Oil 9,900 < 5% Mystic 5 (Intermediate) Operating 130 Oil 10,200 < 5% Mystic 6 (Intermediate) Operating 138 Oil 10,300 < 5% Mystic 7 (Intermediate) Operating 592 Gas/Oil 10,400 30-40% Mystic 8 (Base-load) Operating 807 Gas 6,850 > 70% Mystic 9 (Base-load) Operating 807 Gas 6,850 > 70% Mystic CT (Peaking) Operating 12 Oil 13,500 < 5% New Boston 1 (Peaking) Operating 380 Gas/Oil N/A New Boston 3 (Peaking) Operating 20 Oil N/A West Medway 1 (Peaking) Operating 55 Gas/Oil 13,500 < 5% West Medway 2 (Peaking) Operating 55 Gas/Oil 13,500 < 5% West Medway 3 (Peaking) Operating 55 Gas/Oil 13,500 < 5% Wyman 4 (Peaking) Operating 36 Oil 10,400 < 5% Total Merchant in Operation 3,259 Total MWs 4,066 |
| Sithe Energies Assets Merchant Plants Batavia New York 1 Gas Intermediate 51 Massena New York 1 Gas/Oil Intermediate 68 Ogdensburg New York 1 Gas/Oil Intermediate 71 Cardinal Canada 1 Gas Base-load 157 Qualifying Facilities Allegheny 5, 6, 8, 9 Pennsylvania 4 Hydro Intermediate 50 Bypass Idaho 1 Hydro Base-load 10 Elk Creek Idaho 1 Hydro Base-load 2 Greeley Colorado 1 Gas Base-load 49 Hazelton Idaho 1 Hydro Base-load 9 Independence New York 1 Gas Base-load 617 Ivy River North Carolina 1 Hydro Base-load 1 Kenilworth New Jersey 1 Gas Base-load 26 Montgomery Creek California 1 Hydro Base-load 3 Naval Station California 1 Gas/Oil Base-load 47 Naval Training Center California 1 Gas/Oil Base-load 22 North Island California 1 Gas/Oil Base-load 34 Oxnard California 1 Gas Base-load 48 Rock Creek California 1 Hydro Base-load 4 Sterling New York 1 Gas Intermediate 55 Under Construction Total TEG 1, 2 Mexico Coke Base-load Type of Plant Station Location No. of Units Fuel Dispatch Type Net Generation Capacity (MW) 4 347 18 977 2 228 24 1,552 The following table shows Sithe's principal assets as of December 31, 2002: |
| Midwest Generation PPA Options In 2002, we released 4,411 MWs of options; in 2003, we have 3,043 MWs of options to exercise or release for 2004. We released 578 MWs on 6/24/03 and will decide on remaining 1,778 MWs by early October. Note: All Midwest Gen contracts expire after 2004. Coal PPA (MWs) Coal PPA (MWs) Collins PPA (MWs) Peakers PPA (MWs) Total (MWs) Non-option Option Collins PPA (MWs) Peakers PPA (MWs) Total (MWs) 2002 Capacity 5,645 5,645 2,698 807 9,150 2002 Decision 1,696 3,949 Released 1,614 Released 113 Released 4,411 2002 Decision Released 2,684 Released 2,684 Released 1,614 Released 113 Released 4,411 2003 Capacity 2,961 2,961 1,084 694 4,739 Pending 2003 Decision 1,696 1,265 May release up to 1,084 May release up to 694 May release up to 1,778 (remaining options) Pending 2003 Decision Released 578 Released 578 May release up to 1,084 May release up to 694 May release up to 1,778 (remaining options) Projected 2004 Capacity 2,383 2,383 0 - 1,084 0 - 694 2,383 - 4,161 |
| Political & Regulatory Environment - IL Illinois Commerce Commission New Chairman and two new Commissioners Three Democrats, one Republican, one Independent Legislature (a new day in Springfield) First Democratic Governor in 26 years Democratically controlled House and Senate Only one Republican Constitutional Officer (Treasurer) |
ComEd Restructuring Legislation
Enacted Dec. 1997
Rate Reductions
| • | Residential - | 15% effective 1/1/98 ~ $400 million | ||
| 5% effective 10/1/2001 ~ $100 million |
Direct Access Phase-In Schedule
| • | Residential | |||
| 5/1/2002 | 100% of residential customers have supplier choice. |
| • | Commercial and Industrial, Governmental |
All C&I customers had supplier choice effective 12/31/00.
Transition Cost Recovery Provisions
| 1) | Bundled rates are frozen through 2006 (originally 2004) at 1996 levels after taking the residential rate reductions described above. | |
| 2) | Unbundled delivery service rates apply to customers who choose an alternate supplier or the market rate for energy (ComEd PPO). |
| • | Utilities recover transition costs via a Competitive Transition Charge (CTC) from customers who select an alternate supplier. The CTC will apply through 2006 for all classes. The CTC will be calculated based on the following formula: |
| CTC | = | Tariff/contract revenuesminus | ||
| Delivery service revenueminus | ||||
| Market value of electricityminus | ||||
| Mitigation factor |
(See current and proposed delivery rate schedules attached.)
Mitigation Factor
The mitigation factor is a credit averaging 0.5 cents/kWh offered by the utility to delivery service only customers.
| • | The mitigation factor for commercial and industrial customers is: |
| 10/1/99-12/31/02 | 0.5 cents per kWh or 8% | |
| 2003-2004 | 0.5 cents per kWh or 10% | |
| 2005 | 0.6 cents per kWh or 11% | |
| 2006 | 0.9 cents per kWh or 12% |
| • | The mitigation factor for residential customers is calculated as a percentage of base rates after the rate reductions are in effect. The applicable percentages are as follows: |
| 2002 | 6% of base rates after rate reductions | |
| 2003-2004 | 7% of base rates after rate reductions | |
| 2005 | 8% of base rates after rate reductions | |
| 2006 | 10% of base rates after rate reductions |
Transition Period Provision
During the transition period utilities will be able to recognize, sell or assign assets; retire or remove plants from service; unbundle or restructure tariffs on a revenue neutral basis (with impact limitations described in Earnings and Viability below); accelerate depreciation or amortization or assets without ICC approval. The ICC could intercede if it believed the transaction jeopardized reliable service.
Earnings and Viability
The maximum allowable rate of return will be pegged to the 30-year T-Bond rate, plus 8.5%. If earnings exceed the allowed rate of return by more than 1.5%, 50% of the excess earnings would be shared with customers. If the rate of return is below the T-bond Rate, the utilities can apply to the ICC for a rate increase.
Securitization
Utilities are allowed to utilize securitization of transition period revenues as a means to mitigate stranded costs. The proceeds primarily are to be used to retire debt and equity, and to repay or retire fuel obligations if the Commission finds such use is the public interest.
Amount allowable for securitization is capped by 50% of capitalization. In December 1998, ComEd securitized $3.4 billion.
| ComEd CTC Calculation Bundled Base Rate Average rate by customer class, frozen through 2006 per 1997 Illinois legislation DST Rate Average rate for distribution and transmission services per published tariff Mitigation Factor Guaranteed savings for customers, currently the greater of 10% of the bundled rate or $0.005/kWh MVEC Market value energy component adjusted annually on June 1 CTC Competitive transition charge for recovery of investments made prior to restructuring 100-400 kW Avg. Demand Cents/kWh Bundled Rate 7.428 - DST Rate 1.520 Per published tariff by demand class - Mitigation 0.743 Per 1997 Illinois legislation - MVEC 3.896 Avg. 12-month forward energy prices of trade and bid/ask data from 2/24-3/21/03 = CTC 1.269 |
| ComEd MVEC - How It Works June 2001 March 2002 June 2002 March 2003 June 2003 Bundled 7.428 Energy Prices 7.428 Energy Prices 7.428 DST 1.368 Energy Prices 1.368 Energy Prices 1.520 Mitigation 0.594 Energy Prices 0.594 Energy Prices 0.743 MVEC 5.053 Energy Prices 2.660 Energy Prices 3.896 CTC 0.413 Energy Prices 2.806 Energy Prices 1.269 Changes in MVEC cause inverse change to CTC (100-400 kW avg. demand): Customer Impact Switching (retail electric suppliers (RES) only) as a percent of total 2002 GWh: Small C&I - 17% Large C&I - 35% Total - 15% Potential reduction in CTC revenue beginning 6/03 from customers who buy energy from alternate suppliers Creates potential switching opportunity for other customers |
| ComEd ROE Cap - Earnings Sharing Formula Applies through the end of the transition period (Dec. 31, 2006) Index Calculation: 12-month simple average of "Monthly Treasury Long-Term Average Rates" Plus: 7% Index Adder Plus: 1.5% Index Margin ComEd's two-year average ROE must exceed the two-year average of this index for the same two years before invoking a 50% earnings sharing provision Only the incremental earnings contributing to the percentage in excess of the index is subject to sharing Goodwill is included as equity for purposes of calculating ComEd's ROE |
April 28, 2003
Attachment B1:p 1 of 1
Commonwealth Edison Company
Determination of Nonresidential Customer Transition Charge (Summary Page)
Based on Market Value Defined in Rider PPO — Power Purchase Option (Market Index) Applicable Period A (June 2003 — May 2004)
(All units are in cents per kilowatt-hour)
| Base Rate Revenue | Delivery Service | Mitigation | June 2003 - May 2004 | ||||||||||||||||||
| (1)(2) | Revenue(1)(3) | Market Value (4) | Amount (5) | CTC(6)(7) | |||||||||||||||||
| (A) | (B) | (C) | (D) | (E)=(A)-(B)-(C)-(D) | |||||||||||||||||
| Customer Transition Charge Customer Class | |||||||||||||||||||||
| Nonresidential Delivery Service Customers | |||||||||||||||||||||
| With Only Watt-hour Only Meters | 11.258 | 3.756 | 4.028 | 1.126 | 2.348 | ||||||||||||||||
| 0 kW to and including 25 kW Demand | 9.288 | 2.161 | 3.954 | 0.929 | 2.244 | ||||||||||||||||
| Over 25 kW to and including 100 kW Demand | 8.344 | 1.908 | 3.944 | 0.834 | 1.658 | ||||||||||||||||
| Over 100 kW to and including 400 kW Demand | 7.428 | 1.520 | 3.896 | 0.743 | 1.269 | ||||||||||||||||
| Fixture-included Lighting Nonresidential Delivery Service Customers | 13.554 | 9.754 | 3.059 | 1.355 | 0.000 | ||||||||||||||||
| Street Lighting Delivery Service Customers — Dusk to Dawn | 3.852 | 1.801 | 3.047 | 0.500 | 0.000 | ||||||||||||||||
| Street Lighting Delivery Service Customers — All Other Lighting | 7.172 | 1.794 | 3.514 | 0.717 | 1.147 | ||||||||||||||||
| Railroads Delivery Service Customers (8) | |||||||||||||||||||||
| Pumping Delivery Service Customers | 6.465 | 1.418 | 3.684 | 0.647 | 0.716 | ||||||||||||||||
Notes:
| (1) | Transfer from Column (H) and Column (M) of Determination of Customer Transition Charge, on Pages 5 to 12 of attached work papers. | |
| (2) | Base rate revenues consist of customer, demand, and energy charges. Base rate revenues do not include facility, meter, or other equipment rentals, franchise fees or other franchise cost additions, fuel adjustment clause charges, decommissioning expense adjustment clause charges, taxes, local government compliance clause charges, compensation for energy generated by a person or entity other than ComEd, or Renewable Energy Resources and Coal Technology Development Assistance Charge and Energy Assistance Charge for the Supplemental Low-Income Energy Assistance Fund. | |
| (3) | The amount of revenue that the Company would receive under Rate RCDS — Retail Customer Delivery Service (Rate RCDS) and Rider ISS — Interim Supply Service (Rider ISS) for standard delivery of energy to customers in the CTC Customer Class. | |
| (4) | The Market Value for a CTC Customer Class has the same value as the per kilowatt-hour Load Weighted Average Market Value (LWAMV) as defined in Rider PPO — Power Purchase Option (Market Index) for the applicable customer class for Applicable Period A. | |
| (5) | The mitigation amount as defined in Rate CTC is the greater of 0.5 cents per kilowatt-hour or 10% of the base rate revenue for the calendar years 2003 and 2004. | |
| (6) | This Applicable Period A Customer Transition Charge (CTC) is not applicable if you are taking service under a multi-year CTC option under Rider CTC — MY — Customer Transition Charges — Multi-Year (Rider CTC-MY). Applicable CTCs under a multi-year CTC option are provided on pages 2 through 4. | |
| (7) | CTCs are subject to change without specific notice if one of the components used in the determination of the CTC, as described in Rate CTC, is modified. If the CTC is equal to zero, this account will not be eligible for service under Rider PPO — Power Purchase Option (Market Index) (Rider PPO). | |
| (8) | There are two customers in the Railroads class and each customer will have a Customer-specific CTC. |
April 28, 2003
Attachment B1 R:p 1 of 1
Commonwealth Edison Company
Determination of Residential Customer Transition Charge (Class Summary Page)
Based on Market Value Defined in Rider PPO — Power Purchase Option (Market Index) Applicable Period A (June 2003 — May 2004)
(All units are in cents per kilowatt-hour)
| Base Rate Revenue | Delivery Service | Mitigation | June 2003 - May 2004 | ||||||||||||||||||
| (1)(2) | Revenue (3) | Market Value (4) | Amount (5) | CTC | |||||||||||||||||
| (A) | (B) | (C) | (D) | (E)=(A)-(B)-(C)-(D) | |||||||||||||||||
| Customer Transition Charge Customer Class | |||||||||||||||||||||
| Residential Delivery Service Customers | |||||||||||||||||||||
| Single Family Without Space Heat | 8.715 | 3.355 | 3.911 | 0.610 | 0.839 | ||||||||||||||||
| Multi Family Without Space Heat | 8.961 | 4.404 | 4.057 | 0.627 | 0.000 | ||||||||||||||||
| Single Family With Space Heat | 5.836 | 2.279 | 3.750 | 0.409 | 0.000 | ||||||||||||||||
| Multi Family With Space Heat | 6.169 | 2.881 | 3.818 | 0.432 | 0.000 | ||||||||||||||||
| Fixture-included Lighting Residential Delivery Service Customers | 8.655 | 9.853 | 3.080 | 0.606 | 0.000 | ||||||||||||||||
Notes:
| (1) | Based on three years of residential historical data ending January 2002 and residential rates in effect beginning October 1, 2001. | |
| (2) | Base rate revenues consist of customer service and energy charges. Base rate revenues do not include facility, meter, or other equipment rentals, franchise fees or other franchise cost additions, fuel adjustment clause charges, decommissioning expense adjustment clause charges, taxes, local government compliance class charges, compensation for energy generated by a person or entity other than ComEd, or Renewable Energy Resources and Coal Technology Development Assistance Charge and Energy Assistance Charge for the Supplemental Low-Income Energy Assistance Fund. | |
| (3) | The amount of revenue that the Company would receive under Rate RCDS — Retail Customer Delivery Service (Rate RCDS) and Rider ISS — Interim Supply Service (Rider ISS) for standard delivery of energy to customers in the CTC Customer Class. | |
| (4) | The Market Value for a CTC Customer Class has the same value as the per kilowatt-hour Load Weighted Average Market Value (LWAMV) as defined in Rider PPO — Power Purchase Option (Market Index) for the applicable delivery service customer class. | |
| (5) | The residential mitigation amount as defined in Rate CTC is 7% of the base rate revenue for the calendar years of 2003 and 2004. |
| Five PUC Commissioners - four Republicans, one Democrat (recently appointed) Five-year staggered terms, expiring March 31 of each year Commissioner Fitzpatrick just appointed as Chairman (term expires 3/31/04), replacing Glen Thomas Governor Rendell (D) appointed Wendell Holland (D) as replacement for Commissioner Wilson (R) 2002 legislation allows no more than three Commissioners from the Governor's party Political & Regulatory Environment - PA |
PECO ENERGY
Restructuring Settlement
This summary of the major elements of the 1998 settlement reflects amendments made in 2000 following announcement of the PECO Unicom merger.
| • | Recovery of $5.26 billion of stranded costs over a 12-year transition period beginning January 1, 1999 and ending December 31, 2010, with a return of 10.75 percent. | |
| • | Rate caps will vary over the transition period. (See Table on Page 2.) | |
| • | On January 1, 1999 PECO unbundled rates into three components: |
| • | a transmission and distribution rate of 2.98 cents per kWh. | ||
| • | a competitive transition charge (CTC) designed to recover the $5.26 billion of stranded costs. Revenue collected through the CTC will be reconciled annually based on actual sales. | ||
| • | a shopping credit initially set at 4.46 cents per kWh on a system-wide basis. |
| • | Authorization for PECO to securitize up to $5 billion of stranded costs. (PECO has securitized fully to its $5B limit.) The intangible transition charges associated with transition bonds terminate no later than December 31, 2010. | |
| • | Flexible pricing, within a specified range, for residential default customers. | |
| • | Customer choice phased in between January 1, 1999 and January 2, 2000. | |
| • | Authorization for PECO to transfer its generation assets to a separate entity. | |
| • | Ability of electric generation suppliers (EGS) to provide metering and billing services to retail customers who have direct access. | |
| • | As required by law, on January 1, 2001 the provider of default service for 20 percent of residential customers was bid competitively. | |
| • | If 35 percent and 50 percent of all customers are not shopping by 2001 and 2003, respectively, a number of customers sufficient to equal those trigger points shall be randomly selected and assigned to licensed suppliers by a PUC-determined process. | |
| • | PLR Requirement: PECO is PLR through 2010. |
PECO ENERGY
Schedule of Rates
Schedule of System Average Rates
¢/kWh
| Credit for | ||||||||||||||||||||||||
| Delivery | Generation | |||||||||||||||||||||||
| T&D Rate | Service | Rate | ||||||||||||||||||||||
| Effective Date | Transmission(a) | Distribution | Cap(b) | CTC/ITC | Only | Cap(c) | ||||||||||||||||||
| (1) | (2) | (3) | (4) | (5) | (6) | |||||||||||||||||||
| January 1, 2002 | 0.45 | 2.35 | 2.80 | 2.51 | 4.47 | 6.98 | ||||||||||||||||||
| January 1, 2003 | 0.45 | 2.35 | 2.80 | 2.47 | 4.51 | 6.98 | ||||||||||||||||||
| January 1, 2004 | 0.45 | 2.41 | 2.86 | 2.43 | 4.55 | 6.98 | ||||||||||||||||||
| January 1, 2005 | 0.45 | 2.41 | 2.86 | 2.40 | 4.58 | 6.98 | ||||||||||||||||||
| January 1, 2006 | 0.45 | 2.53 | 2.98 | 2.66 | 4.85 | 7.51 | ||||||||||||||||||
| January 1, 2007 | N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
| January 1, 2008 | N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
| January 1, 2009 | N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
| January 1, 2010 | N/A | N/A | N/A | 2.66 | 5.35 | 8.01 | ||||||||||||||||||
| (a) | Transmission prices listed are for illustration only. The PUC does not regulate rates for transmission Service. | |
| (b) | T&D Rate Cap (column 3) = sum of columns (1)+(2). | |
| (c) | Generation Rate Cap (column 6) = sum of columns (4)+(5). |
Notes:
| • | Average figures for CTC/ITC from 2002-2010 in column 4 are fixed, subject to reconciliation for actual sales levels. | ||
| • | The credit (paid to delivery-service-only-customers) figures in column 5 will be adjusted to reflect changes due to the CTC/ITC reconciliation. | ||
| • | Average transmission and distribution service rates will not exceed the figures in column 3. | ||
| • | The generation portion of bills for customers who remain with regulated PECO generation supply will not, on average, exceed figures in column 6. | ||
| • | Calculation of average rates for 2002: 9.96¢/kWh (existing rate cap) — 1.8 percent reduction = 9.78¢/kWh 9.78¢/kWh = 2.80 (column 3) + 2.51 (column 4) + 4.47 (column 5) |
2
PECO ENERGY
CTC Amortization
Annual Stranded Cost
Amortization and Return(a)
| Revenue, excluding Gross Receipts Tax | ||||||||||||||||||||
| Annual | ||||||||||||||||||||
| Year | Sales | CTC | Total | Return @ 10.75% | Amortization | |||||||||||||||
| MWh | ¢/kWh | ($000) | ($000) | ($000) | ||||||||||||||||
| 2002 | 34,381,485 | 2.51 | 825,004 | 516,869 | 308,135 | |||||||||||||||
| 2003 | 34,656,537 | 2.47 | 818,352 | 482,401 | 335,951 | |||||||||||||||
| 2004 | 34,933,789 | 2.43 | 811,540 | 444,798 | 366,742 | |||||||||||||||
| 2005 | 35,213,260 | 2.40 | 807,933 | 403,555 | 404,378 | |||||||||||||||
| 2006 | 35,494,966 | 2.66 | 902,623 | 353,070 | 549,553 | |||||||||||||||
| 2007 | 35,778,925 | 2.66 | 909,844 | 290,627 | 619,217 | |||||||||||||||
| 2008 | 36,065,157 | 2.66 | 917,123 | 220,312 | 696,811 | |||||||||||||||
| 2009 | 36,353,678 | 2.66 | 924,459 | 141,229 | 783,231 | |||||||||||||||
| 2010 | 36,644,507 | 2.66 | 931,855 | 52,381 | 879,474 | |||||||||||||||
| (a) | Subject to reconciliation of actual sales and collections. Under the settlement, sales are estimated to increase 0.8 percent per year. |
Other Features
| • | The transmission & distribution rate cap of 2.98 cents per kWh includes .01 cent for a sustainable energy and economic development fund during the rate cap period. | |
| • | PECO is permitted to transfer ownership and operation of its generating facilities to a separate corporate entity. The generating facilities will be valued at book value at the time of the transfer. | |
| • | Twenty percent of residential customers will be assigned to a provider of last resort (PLR), other than PECO, on January 1, 2001. The PLR will be selected on the basis of a PUC-approved energy and capacity market price bidding process. PECO-affiliated suppliers will be prohibited from bidding for this block of customers. | |
| • | As of January 1, 2001, PECO (as PLR) will price its service to residential customers within a specified range. | |
| • | A Qualified Rate Order authorizing securitization of up to $4 billion is included (subsequently increased to $5 billion). | |
|
3
Exelon Maturity Schedule — 2003
(Includes issues called to date)
| Refinancing | New Issue | |||||||||||||||||||||||||||||||||||||||||||
| Maturity | Actual Call | Maturity | Pricing | |||||||||||||||||||||||||||||||||||||||||
| Company | Type | Amount ($M) | Coupon | Date | Date | Type | Date | Amount ($M) | Coupon | Date | ||||||||||||||||||||||||||||||||||
Jan | ComEd | FMB | 200.0 | 7.375 | % | 9/15/02 | ||||||||||||||||||||||||||||||||||||||
| ComEd | FMB | 200.0 | 8.375 | % | 9/15/22 | 9/16/02 | ||||||||||||||||||||||||||||||||||||||
| ComEd | Notes | 200.0 | Variable | 9/30/02 | FMB | 2008 | 350.0 | 3.70 | % | 1/14/03 | ||||||||||||||||||||||||||||||||||
| ComEd | Notes | 100.0 | 9.170 | % | 10/15/02 | FMB | 2033 | 350.0 | 5.875 | % | 1/14/03 | |||||||||||||||||||||||||||||||||
Mar | ComEd | Trust Pfd Sec | 200.0 | 8.48 | % | 9/30/35 | 3/20/03 | Trust Pfd Sec | 2033 | 200.0 | 6.35 | % | 3/10/03 | |||||||||||||||||||||||||||||||
Mar | ComEd | FMB | 236.0 | 8.375 | % | 2/15/23 | 3/18/03 | |||||||||||||||||||||||||||||||||||||
| ComEd | FMB | 160.0 | 8.000 | % | 4/15/23 | 4/15/03 | FMB | 2015 | 395.0 | 4.70 | % | 3/31/03 | ||||||||||||||||||||||||||||||||
Apr | PECO | FMB | 250.0 | 6.625 | % | 3/1/03 | ||||||||||||||||||||||||||||||||||||||
| PECO | FMB | 200.0 | 6.500 | % | 5/1/03 | FMB | 2008 | 450.0 | 3.50 | % | 4/21/03 | |||||||||||||||||||||||||||||||||
May | ComEd | Pollution | 40.0 | 5.875 | % | 5/15/07 | 5/15/03 | Pollution | 2017 | 40.0 | Variable* | 5/8/03 | ||||||||||||||||||||||||||||||||
| control bonds | Control bonds | |||||||||||||||||||||||||||||||||||||||||||
June | PECO | Pfd Stock | 50.0 | 7.48 | % | — | 6/11/03 | Trust Pfd Sec | 2033 | 100.0 | 5.75 | % | 6/17/03 | |||||||||||||||||||||||||||||||
| Trust Pfd Sec | 50.0 | 8.00 | % | 6/5/37 | 6/24/03 | |||||||||||||||||||||||||||||||||||||||
| Remaining Maturities | ||||||||||||||||||||||||||||||||||||||||||||
Aug | ComED | FMB | 100.0 | 6.625 | % | 7/15/03 | (new issue pending) | |||||||||||||||||||||||||||||||||||||
Sep | ComED | Notes | 250.0 | Variable | 9/30/03 | |||||||||||||||||||||||||||||||||||||||
| * | The initial 35-day pricing rate is 1.13%. |
Exelon Corporation
Transitional Bond Summary
| ($ in millions) | Dec-00 | Dec-01 | Dec-02 | Dec-03 | Dec-04 | Dec-05 | Dec-06 | Dec-07 | Dec-08 | Dec-09 | Dec-10 | |||||||||||||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||||||||||||||||||
| Year End Principal Balance | $ | 2,720 | $ | 2,380 | $ | 2,040 | $ | 1,700 | $ | 1,360 | $ | 1,020 | $ | 680 | $ | 340 | $ | — | $ | — | $ | — | ||||||||||||||||||||||
| Principal Payments | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | 340 | $ | — | $ | — | ||||||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||||||||||||||||||
| Year End Principal Balance | $ | 4,838 | $ | 4,582 | $ | 4,255 | $ | 4,015 | $ | 3,725 | $ | 3,295 | $ | 2,775 | $ | 2,135 | $ | 1,505 | $ | 805 | $ | — | ||||||||||||||||||||||
| Principal Payments | $ | 256 | $ | 327 | $ | 240 | $ | 290 | $ | 430 | $ | 520 | $ | 640 | $ | 630 | $ | 700 | $ | 805 | ||||||||||||||||||||||||
Total | ||||||||||||||||||||||||||||||||||||||||||||
| Year End Principal Balance | $ | 7,558 | $ | 6,962 | $ | 6,295 | $ | 5,715 | $ | 5,085 | $ | 4,315 | $ | 3,455 | $ | 2,475 | $ | 1,505 | $ | 805 | $ | — | ||||||||||||||||||||||
| Principal Payments | $ | 596 | $ | 667 | $ | 580 | $ | 630 | $ | 770 | $ | 860 | $ | 980 | $ | 970 | $ | 700 | $ | 805 | ||||||||||||||||||||||||
| Securities Ratings for Exelon and its Subsidiary Companies |