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Exelon Corporation
Public Service Enterprise Group

  Edison Electric Institute Financial Conference
  Hollywood, Florida
  November 6-9, 2005


                                                   0
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 of Exelon Corporation (Exelon), Commonwealth Edison Company, PECO Energy
Company, and Exelon Generation Company LLC (collectively, the Exelon Companies) to differ
materially from these forward-looking statements include those discussed herein as well as those
discussed in (1) the Exelon Companies' 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 the Exelon
Companies. The factors that could cause actual results of Public Service Enterprise Group Incorporated
(PSEG), Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Holdings
L.L.C. (collectively, the PSEG Companies) to differ materially from these forward-looking statements
include those discussed herein as well as those discussed in (1) the PSEG Companies' Quarterly
Report on Form 10-Q for the period ended September 30, 2005, in (a) Forward Looking Statements and
(b) ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
and (2) other factors discussed in filings with the SEC by the PSEG Companies. A discussion of risks
associated with the proposed merger of Exelon and 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 Exelon Companies
or the PSEG 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.


                                                                                                           1
Agenda

                                  Tom O’Flynn
 • PSEG Overview
                                  Executive VP and CFO
   – 2005 Performance             Public Service Enterprise Group
   – 2006 Outlook & Environment
   – Merger Update




 • Exelon Overview                John Young
                                  Executive VP, Finance and Markets
   – 2005 Performance
                                  Exelon Corporation
   – 2006 Outlook & Environment
   – Illinois Update




                                                                      2
PSEG Overview - 2005

                                                                              Operating Earnings(1): $770M - $810M
                                                                              EPS Guidance:           $3.15 - $3.35
                                                                              Assets (as of 9/30/05): $30B




                                                        Regional
     Traditional T&D
                                                                                      Domestic/Int’l    Leveraged
                                                     Wholesale Energy
                                                                                        Energy           Leases
                                               Nuclear Capacity: 3,484 MW
Electric Customers:           2.1M
                                               Total Capacity:   14,549 MW
Gas Customers:                1.7M

                                               ~45% of Operating Earnings             ~15% of Operating Earnings
~40% of Operating Earnings


 (1) Includes the parent impact of $(65-75)M; Excludes Merger-related costs
                                                                                                                 3
PSEG YTD 2005 Performance


                                                                         $(0.15)
                                                         $0.18
                                                                                             $2.79 *
                      $(0.02)
      $2.78                             $0.00

                     Improved                         Texas & South    Additional Shares
                                     Weather $0.05
                     Nuclear &                        America $0.15     $(0.06)
                                     Interest $0.03
                     Fossil
                                                      Currency         Parent Interest
                     Operations      O&M    $(0.06)   Impacts $0.03     $(0.09)
                     $0.03
                                     Demand &         Lease
                     Depreciation     Other $(0.02)   Terminations &
                     $(0.04)
                                                      Other $0.04
                     Other $(0.01)
                                                      Repatriation
                                                      $(0.04)


   9/30/04 YTD          Power           PSE&G            Energy            Other            9/30/05 YTD
   Continuing                                           Holdings                           Operating EPS
   Operations
       EPS



* Excludes $0.11 Merger-related costs
                                                                                                           4
2005 Key Events

                                                  Operations
 Natural Gas Price Impact
                                  • Nuclear
• Longer-term Benefits
                                    - 2005 Projected Capacity: 88% vs. 2004: 82%
• Liquidity
                                    - Salem 2 outage: 36 Days
• Customer Impact Dampened
                                    - Salem 1 progressing
   - BGS: 3-year contracts
   - BGSS: storage and hedges
                                  • Fossil
                                   - 10% more MWh’s YTD than last year
                                           - BEC & Lawrenceburg Operational
                                   - 21% improvement in Coal Capacity Factor
         Balance Sheet
• Liquidity
                                              Regulatory
   - $2.1B as of 10/28
                                  • Gas Rate Case
   - $500M of New Facilities
• Cash                               - $133M increase requested
                                        including $55M Depreciation
   - Waterford Sale
                                  • Electric Proceeding
   - Securitization: Year 4 BGS
   - Repatriation                    - $64M Depreciation Credit


                                                                                   5
Attractive Pricing Environment
                                           PJM Western Hub (RTC) Forward Prices and
                                               NYMEX Natural Gas (Henry Hub)
                                                     Henry Hub               PJM West RTC

                                                                                                        110

                           12
                                                                                                        90
                                                                                     BGS
                           10                                                        Auction 4
                                    BGS
                                                             BGS                                        70




                                                                                                              $/MWh
                      $/MBTU




                                    Auction 2
                                                             Auction 3

                               8
                                                                                                        50


                               6
                                                                                                        30



                                4                                                                       10
                               1/1/2003    7/1/2003     1/1/2004    7/1/2004    1/1/2005     7/1/2005

        NYMEX (Henry Hub)            $5.15 - $5.35           $5.25 - $5.40             $6.50 - $6.65
                                     $53                     $55                       $66
BGS Prices (NJ Avg -Approx)

                                     $32 - $33               $36 - $37                 $44 - $46
             PJM West RTC

                                                                                                                      6
         RTC = round the clock
BGS and Long-Term Contracts
                                                                         PSEG Power Term Contracts
                                   100%




                                              2005 BGS
                                   80%
% of Nuclear and Coal Generation




                                                                                                               Generation output not under contract
                                              2004 BGS


                                   60%
                                              2003 BGS


                                   40%
                                          United Illuminating



                                   20%
                                          Other term energy contracts



                                    0%
                                     Oct-05   Jan-06   Apr-06   Jul-06   Oct-06   Jan-07   Apr-07     Jul-07      Oct-07   Jan-08   Apr-08   Jul-08   Oct-08

         % Hedged:                                                                                  65 - 75%                             35 - 50%
                                                            85 - 90%

                                                                                                                                                               7
PSEG Stand-Alone 2006 Earnings Guidance
                                                                                                                          ve
                                                                                                                       Abo
                                                                                                                    lly es
                                                                                                                 gfu    t
                                                                                                             nin 06 Ra
                                                                                                           ea 20
                                                                                                          M
                                                                                                              5-
                                                                                                           200
                                                                                               $3.45
                                                                                                 to
$3.15
                                                                                               $3.75
  to
$3.35                                                   • New
                                       • Gas Base                      • New       • Sales
                                                        Assets
                                        Rate Case                      Assets
                                                                                   • Weather
                                      • Depreciation                 • Inflation   • NDT
                                          Credit
                                                                                                               Driven by
                                                                                                              Commodity
                                                                                                              Prices and
                                                                                                               Contracts
                                                                                                              Rolling Off




  2005       Energy         Unit           Regulatory Depreciation      O&M         Other        2006       2007        2008
Guidance     Prices      Operations          Filings   & Interest                              Guidance

                                                                                                                               8
     NDT = nuclear decommissioning trust
2006 Assumptions and Sensitivities


                       Assumption   Change     Per Share
                                                Impact
  Natural Gas Prices   $10/mmbtu    $1/mmbtu     $0.01
      (NYMEX)

    RTC Energy –        $69/MWh     $5/MWh       $0.05
     PJM West

  Nuclear Capacity       91.4%        1%         $0.04
       Factor

 PJM Capacity Prices    $3/kW-yr    $5/kW-yr     $0.05




                                                           9
Merger Update
      Generation
      PEG:
      EXC:




                   10
Market Concentration Mitigation
7/1/05 – FERC issued merger
                                                                                                                                                                    NY
  approval order

Working with DOJ and NJ BPU                                                                                                                                Bergen
                                                                                                                               Essex
                                                                                                                                                          Hudson
                                                                                                                                        Kearny

4,000MW Fossil Divestiture                                                                                                                        Linden            Bayonne
                                                                                                  PA                                    Sewaren

§ Must complete within 12 months of                                                                                                Edison
  merger closing                                                                                                                             NJ
                                                                                                                            Pennsbury
   §   Peaking: 1,200MW                                                                          Moser                  Falls
   §   High Mid Merit: 900MW                                                                                    Croydon
                                                                                              Cromby
   §   CCGT: 1,200MW                                                                                                                          Mercer

   §                                                                                                                                              Fairless Hills
       Coal: 700MW                                                                                            Richmond
                                                                                                                                             Burlington

§ Merrill Lynch advising on sale
                                                                                                  Eddystone
                                                                                                                                          Delaware
                                                                                                                                             Schuylkill
                                                                                                                                   Southwark
2,600MW Nuclear Virtual Divestiture                                                                           Chester     National Park

§ MDI selected as auction manager
§ LD product sold as “Eastern Nuclear                                                Coal
                                                                                     Combined Cycle
  Generation Aggregate (ENGA)”                                                       Peaking
                                                                                     High Mid Merit

   Notes: The above map includes all EXC & PEG fossil assets in PJM-East that were
   included in Appendix J-12 of Dr. William H. Hieronymus' testimony as part of EXC's
   application under Section 203. Not all of these plants are necessarily under consideration
   for divestiture as part of the mitigation plan. Some of the sites are multi-unit sites; however,
   on this map, the entire site may have been classified under a single category.
                                                                                                                                                                              11
   LD product = liquidated damages product
Merger Regulatory Update
 Status of major filings/approvals:
 •   FERC order approving Merger without hearing issued 7/1/05
      – FERC approved the application as proposed with no surprises
      – New merger review provisions in energy bill do not apply
 •   DOJ Hart-Scott-Rodino review
      – The waiting period expired September 1
      – DOJ review continues, but is not expected to delay closing
 •   Pennsylvania
      – PECO announced settlement with major parties on 9/13/05, subject to approval
      – Final decision expected in December or January
 •   New Jersey
      – Schedule revised; hearings now planned for January
      – Final BPU decision expected in May, unless we settle earlier
 •   SEC
      – PUHCA repeal will be effective Feb. 8
      – No PUHCA order needed unless we close before then


                                                                                       12
EE&G Value Proposition

 • Unmatched scale and scope through merger
 • Stable growth delivery business with improving
   operations
 • Exceptional generation business uniquely
   positioned to benefit from:
    – improving power market fundamentals
    – increasing environmental restrictions on fossil fuels

 • Strong balance sheet and financial discipline
 • Experienced management team


                                                              13
Exelon Update




                14
Exelon Overview - 2005
                                                                                2005E Operating Earnings: $2.0-$2.1B
                                                                                EPS Guidance:            $3.00-$3.15
                                                                                Assets (9/30/05):       $43B




           Traditional T&D                                                       Regional Wholesale Energy
                                                                                    Nuclear Generation
                                                                                     Fossil Generation
                                                                                      Power Marketing
     Illinois             Pennsylvania                                        Nuclear Capacity:     16,900 MW
      Utility                Utility                                                                33,700 MW(1)
                                                                              Total Capacity:

                                                                              ~50% of Operating Earnings
  Electric Customers:                 5.2M
  Gas Customers:                      0.5M

  ~50% of Operating Earnings


   (1) Includes long-term contracts
   Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP

                                                                                                                   15
Exelon YTD 2005 Performance

                                                            $0.19
                                                                                     $(0.15)
                                   $0.16                                                                      $2.37
         $2.17

                                                                             Asbestos reserve $(0.04)
                            Higher margins on               Higher
                                                            delivery
                             market sales $0.36                              O&M                 $(0.03)
                                                            volumes
                                                                             Depreciation &
                            Higher costs to serve
                                                                              amortization       $(0.03)
                             affiliate load $(0.20)
                                                                             Share dilution      $(0.03)
                                                                             Enterprises &
                                                                              all Other          $(0.02)




     9/30/04 YTD                Generation                  Weather                     Other               9/30/05 YTD
    Operating EPS                Margins                                                                   Operating EPS



                            9% growth in operating EPS YTD
 Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP
                                                                                                                           16
Exelon’s EPS Drivers: 2004 - 2007
                             Adjusted (non-GAAP) operating EPS Guidance
                                                                                                 + End of Illinois
                                                                       $3.00-$3.30                 Transition Period
                                   $3.00-$3.15
   $2.78                                                                                         + PECO Generation
                                                                                                   Rate
                                                                                                 + Load Growth
                                                      + Generation
                 + Generation
                                                                                                 - Inflation
                                                        Margins
                   Margins
                                                      + Load Growth
                 + Weather
                                                      - Weather
                 + Load Growth
                                                      - Higher O&M
                 - Other




  2004A                          2005 Estimate                       2006 Estimate                       2007
 Original 2005 Guidance: $2.85 – $3.05



                 Strong earnings growth will continue in 2006
                           and accelerate in 2007
 Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP
                                                                                                                       17
Projected 2005 Key Credit Measures
                                                                                      Credit Ratings(1)
                                                                                     S&P/ Moody’s/ Fitch
     Exelon consolidated:                   FFO / Interest              7.5x           BBB/Baa2/BBB+
                                              FFO / Debt                39%
                                              Debt Ratio                48%

                 Generation:                FFO / Interest             13.6x           BBB+/Baa1/BBB+
                                              FFO / Debt                87%
                                              Debt Ratio                29%

                      ComEd:                FFO / Interest              5.7x                 A-/A3/A-
                                              FFO / Debt                27%
                                                                        41%(2)
                                              Debt Ratio

                        PECO:               FFO / Interest              12.6x                A-/A2/A
                                              FFO / Debt                 36%
                                              Debt Ratio                 45%


                         Exelon’s Balance Sheet is strong
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 and Generation and senior secured ratings for ComEd and

PECO; (2) Assumes half of ComEd goodwill is written off
                                                                                                           18
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     Genco     Exelon
                Generation Margin        -         +         +
                      DST                +        N/A        +
               Net Earnings Impact       -         +         +

 • ComEd is willing to work with stakeholders to mitigate the potential
   customer impacts of transitioning to market prices for generation

 Net Impact on earnings is expected to be positive for Exelon overall


                                                                                    19
Composition of Operating Earnings
 100%
  90%
  80%
  70%
  60%                                                                               PECO
  50%                                                                               ComEd
                                                                                    Generation
  40%
  30%
  20%
  10%
   0%
             2002          2003           2004          2005E       2006E   2007*
  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

    * Based on Thomson First Call consensus EPS estimate of $4.20
                                                                                                 20
Illinois Update




                  21
1997 Illinois Restructuring Act
Consumers have benefited:
• Since 1997, ComEd residential electric rates have been reduced 20% and frozen
  through the end of 2006
• As a result, residential customers will have enjoyed $4 billion in savings during this
  period
Competition has developed:
•   More than 50% of large customer load >1 MW served by retail energy suppliers
•   23.5% of ComEd’s total load served by retail energy suppliers
•   18 suppliers certified by the Illinois Commerce Commission
•   Eight suppliers serving 20,000 GWh load
Exelon has restructured:
• As a result of the 1997 Act, the company was separated into two businesses
• We have used the restructuring and transition period to improve both delivery and
  generation businesses
   – Invested $3 billion in T&D infrastructure over past 5 years for improved reliability
   – Nuclear capacity factor has risen to 93+% and nuclear production costs are down
      from $26.80 per MWh at ComEd in 1997 to $12.43 per MWh fleet wide in 2004

         The Illinois Restructuring Act has benefited both customers
                               and shareholders


                                                                                            22
Moving Illinois Forward
 Summer 2004 – ICC Stakeholder Workshops
 • Consensus develops around the use of a competitive procurement process for
   establishing market-based rates post 2006
 • ICC staff report recommends a reverse auction (like New Jersey’s) as the best
   available competitive procurement process
 February 2005 – ComEd files Procurement Case
 • Auction patterned after successful process in NJ and will result in a reliable power
   supply at the lowest-available market price
 • Hearings were recently completed and a final ICC order is due in January 2006
 August 2005 – ComEd files Delivery Case
 • Traditional rate case to recover prudently incurred costs to provide delivery service
 • A final ICC order is due in July 2006


        Process is well underway to determine post-transition rates


                                                                                           23
Actions Underway
• Regulatory
   – Trying to keep the ICC process on track
   – Seeking FERC determination through Section 205 filing that affiliate contracts won
     through a reverse auction process will meet Edgar Standards and will be approved
• Legal
   – Intervening in Attorney General’s court case
   – Recently appointed ICC Chairman, who was former Executive Director of CUB,
     not confirmed by full Senate so ComEd recusal motion is moot
• Legislative
   – Working to prevent adverse legislation
• Media and other outreach
   – CORE
   – Ad campaign
   – Business community support
• Ring fencing ComEd
   – Pursuing appropriate financial, legal and governance actions

                Working with major stakeholders to reach a
                         reasonable resolution


                                                                                          24
In Summary

• Continued strong financial performance at both PSEG
  and ComEd

• Merger approvals and integration efforts on track

• Combined company well positioned for future
  earnings growth


• Expect to resolve Illinois issues to the benefit of both
  our customers and shareholders


                                                             25
Appendix




           26
Key Competitive Pressure: BGS Auction Results



                         20,000
                                                         NJ BGS Auction Structure
Total NJ BGS Load (MW)




                         16,000

                                                                         1 Year
                                                          10                             2005 FP Auction Load
                         12,000                                         50
                                                         months                              50 Tranches
                                                                     Tranches
                                                        104
                                         1 Year
                                                                                     3 Years
                                                     Tranches
                          8,000                                                                                  2007 FP Auction Load
                                         170
                                                                                                                 (projected)
                                                                                   51 Tranches
                                      Tranches
                                                              34 months
                          4,000
                                                                                                      2006 FP Auction Load
                                                             51 Tranches                              (projected)

                                  2002            2003            2004            2005         2006       2007          2008




                   * Annualized margin to forward curve on date of BGS auction

                                                                                                                                        27
2005 BGS Auction Results


                                                     $65.91
                                                 (36 Month NJ Avg.)
                                $54.45
            $52.70                                                    •   Transmission
                                                                      •   Ancillary services
                            (12 Month NJ Avg.)
       (10 Month NJ Avg.)
                                                    ~ $21             •   Load shape
                                                                      •   Congestion
                                ~ $18                                 •   Risk premium
             ~ $20                                                    •   Capacity




                                                   $44 -$46
                               $36 -$37                                   RTC Forward
           $32 - $33                                                      Energy Cost



           2003 Auction       2004 Auction        2005 Auction

  RTC = round the clock




                                                                                         28
Anticipated Merger Timeline
Dec 2004         Q1 2005          Q2 2005         Q3 2005          Q4 2005             Q1 2006       Q2 2006
Dec 2004         Q1 2005          Q2 2005         Q3 2005          Q4 2005             Q1 2006       Q2 2006
 Announce          FERC,                             FERC               PA PUC Final
 Announce           FERC,                            FERC
Transaction      NJBPU, ICC                        Approval               Decision
Transaction      NJBPU, ICC                         Approval
  12/20/04       Regulatory                       Order 7/1/05           Expected
  12/20/04        Regulatory                      Order 7/1/05
                   Filings
                    Filings
                                                  Shareholder
                   2/4/05                         Shareholder
                    2/4/05                                                         NJ Settlement
                                                                                   NJ Settlement
                                                   Approvals
                                                   Approvals                       Discussions
                                                                                    Discussions
                                                     7/05
                  File Joint                          7/05
                   File Joint
                    Proxy
                     Proxy                                                              NJ BPU      NJ BPU Final
                                                  Respond to                             NJ BPU      NJ BPU Final
                  Statement                       Respond to
                  Statement                                                             Hearings      Decision
                                                   DOJ 2nd                              Hearings       Decision
                                                    DOJ 2nd
                   2/10/05
                    2/10/05                                                            Scheduled      Expected,
                                                   Request                             Scheduled      Expected,
                                                    Request
                                                                                                    unless Settled
                                                                                                    unless Settled
                                                                                                        Earlier
                                                   Settlement                                           Earlier
                                                   Settlement
                                                  with PA PUC
                                                  with PA PUC
                                                  Filed 9/13/05
                                                  Filed 9/13/05

                                Beginning 1/17/05, Implement Nuclear Operating Services Agreement
                                Beginning 1/17/05, Implement Nuclear Operating Services Agreement

                                             Develop Transition Implementation Plans
                                             Develop Transition Implementation Plans

                                              Work to Secure Regulatory Approvals
                                               Work to Secure Regulatory Approvals
                                       (FERC, DOJ, ICC*, PAPUC, NJBPU, SEC, and others)
                                        (FERC, DOJ, ICC*, PAPUC, NJBPU, SEC, and others)

                                                                                  CLOSE TRANSACTION
                                                                                  CLOSE TRANSACTION
     * Notice filing only


                                                                                                              29
Marginal Revenue and Cost per MWh of
Retail Load in 3Q 05
                                                                  Illustration Using Approximate 3Q 05 Data
             Illustration Using Approximate 3Q 05 Data
$/MWh
   150
               Genco                    ComEd                     Genco                    PECO
                                                                                              $101
   100
                                            $75                                                         Gen*
                                                                                               $45
                                                     Gen*
                                            $40
    50                                                                                                  CTC
                                                                                               $24
                                                     CTC
                                            $14                       $45
                  $40                                                                          $32
                              Genco/                                             Genco/                 T&D
                                            $21      T&D
        0                     ComEd                                              PECO
                               PPA                                                PPA
                                            ($40)                                             ($45)
                  ($61)
    -50
                               Cost to serve incremental
                                                                      ($91)
                                 switching load in the
                 ($78)
   -100                           spot market in 3Q


   -150                   Cost to serve incremental                  ($140)
                          weather-driven load in the
                             spot market in 3Q
   -200
                 * Excludes line losses, ancillaries and gross receipts taxes


        Generation serves both ComEd’s and PECO’s load
                   at fixed, below-market rates
                                                                                                               30
Profit Impact of Higher Sales at ComEd
 and PECO in 3Q 05
Illustration Using Approximate 3Q 05 Data:
                                                         Higher Sales to PECO
Higher Sales to ComEd

                                                         $/MWh       PECO       Genco   Exelon
$/MWh           ComEd        Genco         Exelon
                                                         Weather
Weather
                                                           Revenue      101       45     101
  Revenue          75            40            75
                                                           Cost*        (45)    (140)   (140)
  Cost*           (40)          (78)          (78)
                                                           Margin        56      (95)    (39)
  Margin           35           (38)            (3)

                                                         Switching
Switching
                                                           Revenue      45        45      45
  Revenue          40            40            40
                                                           Cost*       (45)      (91)    (91)
  Cost*           (40)          (61)          (61)
                                                           Margin        --      (46)    (46)
  Margin            --          (21)          (21)


       * Cost to serve incremental load in spot market

      • Warm summer weather was favorable for Delivery but
        unfavorable for Generation and Exelon overall
      • Higher customer retention was neutral for Delivery and
        unfavorable for Generation and Exelon Overall
                                                                                                 31
Consolidated – Key Assumptions
                                                    2004A     2005E     2006E

                                     (1)             93.5      93.9      92.9
 Nuclear Capacity Factor (%)
                                                    202,599   220,700   193,700
 Total Genco Sales Ex Trading (GWhs)
                                                    110,465   119,400   118,700
 Total Sales to Energy Delivery (GWhs)
                                                     92,134   101,200    75,000
 Total Market and Retail Sales (GWhs)
 Volume Retention (%)
                                                      88        94        95
   PECO
                                                      77        79        76
   ComEd
                           (2)
 Delivery Growth (%)
                                                      3.8       0.2       2.6
    PECO
                                                      3.3       1.2       2.2
    ComEd
 Elec. Wholesale Mkt. ATC Price ($/MWh)
                                                     31.15     40.00     43.00
    PJM Midwest (NiHUB)
                                                     42.34     49.00     54.00
    PJM Mid-Atlantic (West Hub)
                                                      36.5      37.5      37.5
 Effective Tax Rate (%)

 Note: Data for Exelon stand-alone
 A = Actual; E = Estimate; ATC = Around the clock
 (1) Excludes Salem
 (2) Weather Normalized


   Source: 8/5/05 Exelon Investor Conference

                                                                                  32
Portfolio Sensitivities for Genco

     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        Power -$1.00
                                                           ATC*                ATC*
                        Sep to Dec 2005                       $4                 ($3)

                             Calendar 2006                   $28                 ($27)


  * ATC = Around the Clock



   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




   Source: 8/5/05 Exelon Investor Conference

                                                                                           33
Deploying Our Cash
              $5.0

              $4.0

              $3.0                                    Aug-04 Projected
                                                       Free Cash Flow
                                                                               4.0
              $2.0                        3.8
                                                                                                          Net Cash from Operations
              $1.0
 $ Billions




              $0.0
                                                                                                         Transition Debt Retirements
                                         (0.8)                                (0.9)
              ($1.0)                     (0.5)                                                           Nuclear Fuel
                                                                              (0.5)
                                         (0.6)                                (0.6)                      Genco CapEx
              ($2.0)                                  Current Projected
                                         (1.0)         Free Cash Flow         (1.1)                      EED CapEx
              ($3.0)
                                                                              (0.1)                     Corp. CapEx
                                         (1.1)
              ($4.0)                                                          (1.1)                      Dividends

              ($5.0)                     2005E                                2006E

              Our current cash flow forecast reflects increased investments in the core
                             business – mainly on the regulated side
       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.
              Source: 8/5/05 Exelon Investor Conference
                                                                                                                                       34
Exelon Consolidated GAAP Earnings to Adjusted
(non-GAAP) Operating Earnings – YTD through Sept.
     (in Millions, except EPS)
                                                                                A                  B                              C                   D               E                                     F
                                                                                                   YTD 2005                                                                YTD 2004
                                                                                                                              Operating                                                                 Operating
                                                                               GAAP           Adjustments                     Earnings               GAAP        Adjustments                            Earnings
Line

       Operating revenues                                                  $   11,519         $         -                     $   11,519         $   10,821      $        (248) (e)                     $   10,573
 1


       Fuel & purchased power                                                    4,012                  152 (a)                    4,164              3,781               (187) (a),(e)                      3,594
 2

        Revenue Net Fuel                                                         7,507                 (152)                       7,355              7,040                (61)                              6,979
 3
       Operating & maintenance                                                   2,804                  (76) (b),(c),(h)           2,728              2,696               (137) (b),(e),(h),(j)              2,559
 4
       Depreciation & amortization                                               1,003                  (56) (b),(c)                 947                974                (40) (b),(e)                        934
 5
                                                                                                                                                        548                 (9) (e)                            539
       Taxes other than income                                                     560                  -                            560
 6

                                                                                                                                                      4,218               (186)                              4,032
         Total operating expenses                                                4,367                 (132)                       4,235
 7

                                                                                                                                                      2,822               125                                2,947
       Operating income                                                          3,140                  (20)                       3,120
 8
                                                                                                                                                       (633)               19 (b),(e)                         (614)
       Interest expense                                                           (615)                  11 (b)                     (604)
 9
                                                                                                                                                        (97)               48 (b)                               (49)
       Equity in Earnings                                                         (107)                  86 (b)                       (21)
10
                                                                                                                                                         43                16 (e),(i)                            59
       Other, net                                                                  108                    -                          108
11

                                                                                                                                                      2,135               208                                2,343
       Income from continuing operations, pre-tax                                2,526                   77                        2,603
12

                                                                                                                                                        661               230 (a),(b),(e),(h),(i),(j)          891
       Income taxes                                                                779                  220 (a),(b),(c),(h)          999
13
                                                                                                                                                      1,477                (22)                              1,455
       Income from continuing operations                                         1,747                 (143)                       1,604
14

                                                                                                                                                            1              -                                      1 (g)
       Gains (losses) from discontinued operations                                   13                 (16) (d)                           (3)
15

                                                                                                                                                           23              (32) (f)                               (9)
       Cumulative effect of a change in accounting                                   -                  -                              -
16

                                                                                                                                                 $    1,501      $         (54)                         $    1,447
       Net income                                                          $     1,760        $        (159)                  $    1,601
17

                                                                                                                                                 $        2.25                                          $       2.17
       Earnings per share (diluted)                                        $        2.60                                      $       2.37
18




           Adjustment to exclude the mark-to-market impact of Exelon's non-trading activities (primarily at Generation).
       (a)
           Adjustment to exclude the financial impact of Exelon's investments in synthetic fuel-producing facilities.
       (b)
       (c) Adjustment to exclude costs associated with Exelon's anticipated merger with Public Service Enterprise Group Inc.
       (d) Adjustment to exclude the 2005 financial impact of Generation's investment in Sithe Energies, Inc.
       (e) Adjustment to exclude the 2004 financial impact of Boston Generating, LLC.
           Adjustment for the cumulative effect of adopting FIN No. 46-R.
       (f)
           Includes the 2004 financial impact of Enterprises.
       (g)
       (h) Adjustment to exclude severance charges.
       (i) Adjustment to exclude the losses associated with debt retirements at ComEd.
             Adjustment for a settlement gain related to the storage of spent nuclear fuel.
       (j)




                           Note: Items may not add due to rounding.

                                                                                                                                                                                                                        35
Reconciliation of 2004 GAAP Reported and Adjusted (non-GAAP)
Operating Earnings per Diluted Share


       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




                                                                               36
2005/2006 Earnings Guidance


  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, certain severance costs, the cumulative effect of the adoption
  of FIN 47 – “Accounting for Conditional Asset Retirement Obligations,”
  and costs associated with the proposed merger with PSEG. The
  outlook for 2006 adjusted (non-GAAP) operating earnings is Exelon
  stand-alone and excludes unrealized mark-to-market adjustments
  from non-trading activities, income resulting from investments in
  synthetic fuel-producing facilities and costs associated with the
  proposed merger. These estimates do not include any impact of
  future changes to GAAP. Earnings guidance is based on the
  assumption of normal weather.



                                                                             37
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




                                                                       38
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
Preferred Securities of Subsidiaries
Adjusted Book Debt
Total Adjusted Capitalization

Note: FFO and Debt related to non-recourse debt are excluded from the calculations.

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public serviceenterprise group ExelonEEI

  • 1. Exelon Corporation Public Service Enterprise Group Edison Electric Institute Financial Conference Hollywood, Florida November 6-9, 2005 0
  • 2. 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 of Exelon Corporation (Exelon), Commonwealth Edison Company, PECO Energy Company, and Exelon Generation Company LLC (collectively, the Exelon Companies) to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) the Exelon Companies' 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 the Exelon Companies. The factors that could cause actual results of Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Holdings L.L.C. (collectively, the PSEG Companies) to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) the PSEG Companies' Quarterly Report on Form 10-Q for the period ended September 30, 2005, in (a) Forward Looking Statements and (b) ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations and (2) other factors discussed in filings with the SEC by the PSEG Companies. A discussion of risks associated with the proposed merger of Exelon and 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 Exelon Companies or the PSEG 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. 1
  • 3. Agenda Tom O’Flynn • PSEG Overview Executive VP and CFO – 2005 Performance Public Service Enterprise Group – 2006 Outlook & Environment – Merger Update • Exelon Overview John Young Executive VP, Finance and Markets – 2005 Performance Exelon Corporation – 2006 Outlook & Environment – Illinois Update 2
  • 4. PSEG Overview - 2005 Operating Earnings(1): $770M - $810M EPS Guidance: $3.15 - $3.35 Assets (as of 9/30/05): $30B Regional Traditional T&D Domestic/Int’l Leveraged Wholesale Energy Energy Leases Nuclear Capacity: 3,484 MW Electric Customers: 2.1M Total Capacity: 14,549 MW Gas Customers: 1.7M ~45% of Operating Earnings ~15% of Operating Earnings ~40% of Operating Earnings (1) Includes the parent impact of $(65-75)M; Excludes Merger-related costs 3
  • 5. PSEG YTD 2005 Performance $(0.15) $0.18 $2.79 * $(0.02) $2.78 $0.00 Improved Texas & South Additional Shares Weather $0.05 Nuclear & America $0.15 $(0.06) Interest $0.03 Fossil Currency Parent Interest Operations O&M $(0.06) Impacts $0.03 $(0.09) $0.03 Demand & Lease Depreciation Other $(0.02) Terminations & $(0.04) Other $0.04 Other $(0.01) Repatriation $(0.04) 9/30/04 YTD Power PSE&G Energy Other 9/30/05 YTD Continuing Holdings Operating EPS Operations EPS * Excludes $0.11 Merger-related costs 4
  • 6. 2005 Key Events Operations Natural Gas Price Impact • Nuclear • Longer-term Benefits - 2005 Projected Capacity: 88% vs. 2004: 82% • Liquidity - Salem 2 outage: 36 Days • Customer Impact Dampened - Salem 1 progressing - BGS: 3-year contracts - BGSS: storage and hedges • Fossil - 10% more MWh’s YTD than last year - BEC & Lawrenceburg Operational - 21% improvement in Coal Capacity Factor Balance Sheet • Liquidity Regulatory - $2.1B as of 10/28 • Gas Rate Case - $500M of New Facilities • Cash - $133M increase requested including $55M Depreciation - Waterford Sale • Electric Proceeding - Securitization: Year 4 BGS - Repatriation - $64M Depreciation Credit 5
  • 7. Attractive Pricing Environment PJM Western Hub (RTC) Forward Prices and NYMEX Natural Gas (Henry Hub) Henry Hub PJM West RTC 110 12 90 BGS 10 Auction 4 BGS BGS 70 $/MWh $/MBTU Auction 2 Auction 3 8 50 6 30 4 10 1/1/2003 7/1/2003 1/1/2004 7/1/2004 1/1/2005 7/1/2005 NYMEX (Henry Hub) $5.15 - $5.35 $5.25 - $5.40 $6.50 - $6.65 $53 $55 $66 BGS Prices (NJ Avg -Approx) $32 - $33 $36 - $37 $44 - $46 PJM West RTC 6 RTC = round the clock
  • 8. BGS and Long-Term Contracts PSEG Power Term Contracts 100% 2005 BGS 80% % of Nuclear and Coal Generation Generation output not under contract 2004 BGS 60% 2003 BGS 40% United Illuminating 20% Other term energy contracts 0% Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 % Hedged: 65 - 75% 35 - 50% 85 - 90% 7
  • 9. PSEG Stand-Alone 2006 Earnings Guidance ve Abo lly es gfu t nin 06 Ra ea 20 M 5- 200 $3.45 to $3.15 $3.75 to $3.35 • New • Gas Base • New • Sales Assets Rate Case Assets • Weather • Depreciation • Inflation • NDT Credit Driven by Commodity Prices and Contracts Rolling Off 2005 Energy Unit Regulatory Depreciation O&M Other 2006 2007 2008 Guidance Prices Operations Filings & Interest Guidance 8 NDT = nuclear decommissioning trust
  • 10. 2006 Assumptions and Sensitivities Assumption Change Per Share Impact Natural Gas Prices $10/mmbtu $1/mmbtu $0.01 (NYMEX) RTC Energy – $69/MWh $5/MWh $0.05 PJM West Nuclear Capacity 91.4% 1% $0.04 Factor PJM Capacity Prices $3/kW-yr $5/kW-yr $0.05 9
  • 11. Merger Update Generation PEG: EXC: 10
  • 12. Market Concentration Mitigation 7/1/05 – FERC issued merger NY approval order Working with DOJ and NJ BPU Bergen Essex Hudson Kearny 4,000MW Fossil Divestiture Linden Bayonne PA Sewaren § Must complete within 12 months of Edison merger closing NJ Pennsbury § Peaking: 1,200MW Moser Falls § High Mid Merit: 900MW Croydon Cromby § CCGT: 1,200MW Mercer § Fairless Hills Coal: 700MW Richmond Burlington § Merrill Lynch advising on sale Eddystone Delaware Schuylkill Southwark 2,600MW Nuclear Virtual Divestiture Chester National Park § MDI selected as auction manager § LD product sold as “Eastern Nuclear Coal Combined Cycle Generation Aggregate (ENGA)” Peaking High Mid Merit Notes: The above map includes all EXC & PEG fossil assets in PJM-East that were included in Appendix J-12 of Dr. William H. Hieronymus' testimony as part of EXC's application under Section 203. Not all of these plants are necessarily under consideration for divestiture as part of the mitigation plan. Some of the sites are multi-unit sites; however, on this map, the entire site may have been classified under a single category. 11 LD product = liquidated damages product
  • 13. Merger Regulatory Update Status of major filings/approvals: • FERC order approving Merger without hearing issued 7/1/05 – FERC approved the application as proposed with no surprises – New merger review provisions in energy bill do not apply • DOJ Hart-Scott-Rodino review – The waiting period expired September 1 – DOJ review continues, but is not expected to delay closing • Pennsylvania – PECO announced settlement with major parties on 9/13/05, subject to approval – Final decision expected in December or January • New Jersey – Schedule revised; hearings now planned for January – Final BPU decision expected in May, unless we settle earlier • SEC – PUHCA repeal will be effective Feb. 8 – No PUHCA order needed unless we close before then 12
  • 14. EE&G Value Proposition • Unmatched scale and scope through merger • Stable growth delivery business with improving operations • Exceptional generation business uniquely positioned to benefit from: – improving power market fundamentals – increasing environmental restrictions on fossil fuels • Strong balance sheet and financial discipline • Experienced management team 13
  • 16. Exelon Overview - 2005 2005E Operating Earnings: $2.0-$2.1B EPS Guidance: $3.00-$3.15 Assets (9/30/05): $43B Traditional T&D Regional Wholesale Energy Nuclear Generation Fossil Generation Power Marketing Illinois Pennsylvania Nuclear Capacity: 16,900 MW Utility Utility 33,700 MW(1) Total Capacity: ~50% of Operating Earnings Electric Customers: 5.2M Gas Customers: 0.5M ~50% of Operating Earnings (1) Includes long-term contracts Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP 15
  • 17. Exelon YTD 2005 Performance $0.19 $(0.15) $0.16 $2.37 $2.17 Asbestos reserve $(0.04) Higher margins on Higher delivery market sales $0.36 O&M $(0.03) volumes Depreciation & Higher costs to serve amortization $(0.03) affiliate load $(0.20) Share dilution $(0.03) Enterprises & all Other $(0.02) 9/30/04 YTD Generation Weather Other 9/30/05 YTD Operating EPS Margins Operating EPS 9% growth in operating EPS YTD Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP 16
  • 18. Exelon’s EPS Drivers: 2004 - 2007 Adjusted (non-GAAP) operating EPS Guidance + End of Illinois $3.00-$3.30 Transition Period $3.00-$3.15 $2.78 + PECO Generation Rate + Load Growth + Generation + Generation - Inflation Margins Margins + Load Growth + Weather - Weather + Load Growth - Higher O&M - Other 2004A 2005 Estimate 2006 Estimate 2007 Original 2005 Guidance: $2.85 – $3.05 Strong earnings growth will continue in 2006 and accelerate in 2007 Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP 17
  • 19. Projected 2005 Key Credit Measures Credit Ratings(1) S&P/ Moody’s/ Fitch Exelon consolidated: FFO / Interest 7.5x BBB/Baa2/BBB+ FFO / Debt 39% Debt Ratio 48% Generation: FFO / Interest 13.6x BBB+/Baa1/BBB+ FFO / Debt 87% Debt Ratio 29% ComEd: FFO / Interest 5.7x A-/A3/A- FFO / Debt 27% 41%(2) Debt Ratio PECO: FFO / Interest 12.6x A-/A2/A FFO / Debt 36% Debt Ratio 45% Exelon’s Balance Sheet is strong 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 and Generation and senior secured ratings for ComEd and PECO; (2) Assumes half of ComEd goodwill is written off 18
  • 20. 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 Genco Exelon Generation Margin - + + DST + N/A + Net Earnings Impact - + + • ComEd is willing to work with stakeholders to mitigate the potential customer impacts of transitioning to market prices for generation Net Impact on earnings is expected to be positive for Exelon overall 19
  • 21. Composition of Operating Earnings 100% 90% 80% 70% 60% PECO 50% ComEd Generation 40% 30% 20% 10% 0% 2002 2003 2004 2005E 2006E 2007* 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 * Based on Thomson First Call consensus EPS estimate of $4.20 20
  • 23. 1997 Illinois Restructuring Act Consumers have benefited: • Since 1997, ComEd residential electric rates have been reduced 20% and frozen through the end of 2006 • As a result, residential customers will have enjoyed $4 billion in savings during this period Competition has developed: • More than 50% of large customer load >1 MW served by retail energy suppliers • 23.5% of ComEd’s total load served by retail energy suppliers • 18 suppliers certified by the Illinois Commerce Commission • Eight suppliers serving 20,000 GWh load Exelon has restructured: • As a result of the 1997 Act, the company was separated into two businesses • We have used the restructuring and transition period to improve both delivery and generation businesses – Invested $3 billion in T&D infrastructure over past 5 years for improved reliability – Nuclear capacity factor has risen to 93+% and nuclear production costs are down from $26.80 per MWh at ComEd in 1997 to $12.43 per MWh fleet wide in 2004 The Illinois Restructuring Act has benefited both customers and shareholders 22
  • 24. Moving Illinois Forward Summer 2004 – ICC Stakeholder Workshops • Consensus develops around the use of a competitive procurement process for establishing market-based rates post 2006 • ICC staff report recommends a reverse auction (like New Jersey’s) as the best available competitive procurement process February 2005 – ComEd files Procurement Case • Auction patterned after successful process in NJ and will result in a reliable power supply at the lowest-available market price • Hearings were recently completed and a final ICC order is due in January 2006 August 2005 – ComEd files Delivery Case • Traditional rate case to recover prudently incurred costs to provide delivery service • A final ICC order is due in July 2006 Process is well underway to determine post-transition rates 23
  • 25. Actions Underway • Regulatory – Trying to keep the ICC process on track – Seeking FERC determination through Section 205 filing that affiliate contracts won through a reverse auction process will meet Edgar Standards and will be approved • Legal – Intervening in Attorney General’s court case – Recently appointed ICC Chairman, who was former Executive Director of CUB, not confirmed by full Senate so ComEd recusal motion is moot • Legislative – Working to prevent adverse legislation • Media and other outreach – CORE – Ad campaign – Business community support • Ring fencing ComEd – Pursuing appropriate financial, legal and governance actions Working with major stakeholders to reach a reasonable resolution 24
  • 26. In Summary • Continued strong financial performance at both PSEG and ComEd • Merger approvals and integration efforts on track • Combined company well positioned for future earnings growth • Expect to resolve Illinois issues to the benefit of both our customers and shareholders 25
  • 27. Appendix 26
  • 28. Key Competitive Pressure: BGS Auction Results 20,000 NJ BGS Auction Structure Total NJ BGS Load (MW) 16,000 1 Year 10 2005 FP Auction Load 12,000 50 months 50 Tranches Tranches 104 1 Year 3 Years Tranches 8,000 2007 FP Auction Load 170 (projected) 51 Tranches Tranches 34 months 4,000 2006 FP Auction Load 51 Tranches (projected) 2002 2003 2004 2005 2006 2007 2008 * Annualized margin to forward curve on date of BGS auction 27
  • 29. 2005 BGS Auction Results $65.91 (36 Month NJ Avg.) $54.45 $52.70 • Transmission • Ancillary services (12 Month NJ Avg.) (10 Month NJ Avg.) ~ $21 • Load shape • Congestion ~ $18 • Risk premium ~ $20 • Capacity $44 -$46 $36 -$37 RTC Forward $32 - $33 Energy Cost 2003 Auction 2004 Auction 2005 Auction RTC = round the clock 28
  • 30. Anticipated Merger Timeline Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Q2 2006 Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Q2 2006 Announce FERC, FERC PA PUC Final Announce FERC, FERC Transaction NJBPU, ICC Approval Decision Transaction NJBPU, ICC Approval 12/20/04 Regulatory Order 7/1/05 Expected 12/20/04 Regulatory Order 7/1/05 Filings Filings Shareholder 2/4/05 Shareholder 2/4/05 NJ Settlement NJ Settlement Approvals Approvals Discussions Discussions 7/05 File Joint 7/05 File Joint Proxy Proxy NJ BPU NJ BPU Final Respond to NJ BPU NJ BPU Final Statement Respond to Statement Hearings Decision DOJ 2nd Hearings Decision DOJ 2nd 2/10/05 2/10/05 Scheduled Expected, Request Scheduled Expected, Request unless Settled unless Settled Earlier Settlement Earlier Settlement with PA PUC with PA PUC Filed 9/13/05 Filed 9/13/05 Beginning 1/17/05, Implement Nuclear Operating Services Agreement Beginning 1/17/05, Implement Nuclear Operating Services Agreement Develop Transition Implementation Plans Develop Transition Implementation Plans Work to Secure Regulatory Approvals Work to Secure Regulatory Approvals (FERC, DOJ, ICC*, PAPUC, NJBPU, SEC, and others) (FERC, DOJ, ICC*, PAPUC, NJBPU, SEC, and others) CLOSE TRANSACTION CLOSE TRANSACTION * Notice filing only 29
  • 31. Marginal Revenue and Cost per MWh of Retail Load in 3Q 05 Illustration Using Approximate 3Q 05 Data Illustration Using Approximate 3Q 05 Data $/MWh 150 Genco ComEd Genco PECO $101 100 $75 Gen* $45 Gen* $40 50 CTC $24 CTC $14 $45 $40 $32 Genco/ Genco/ T&D $21 T&D 0 ComEd PECO PPA PPA ($40) ($45) ($61) -50 Cost to serve incremental ($91) switching load in the ($78) -100 spot market in 3Q -150 Cost to serve incremental ($140) weather-driven load in the spot market in 3Q -200 * Excludes line losses, ancillaries and gross receipts taxes Generation serves both ComEd’s and PECO’s load at fixed, below-market rates 30
  • 32. Profit Impact of Higher Sales at ComEd and PECO in 3Q 05 Illustration Using Approximate 3Q 05 Data: Higher Sales to PECO Higher Sales to ComEd $/MWh PECO Genco Exelon $/MWh ComEd Genco Exelon Weather Weather Revenue 101 45 101 Revenue 75 40 75 Cost* (45) (140) (140) Cost* (40) (78) (78) Margin 56 (95) (39) Margin 35 (38) (3) Switching Switching Revenue 45 45 45 Revenue 40 40 40 Cost* (45) (91) (91) Cost* (40) (61) (61) Margin -- (46) (46) Margin -- (21) (21) * Cost to serve incremental load in spot market • Warm summer weather was favorable for Delivery but unfavorable for Generation and Exelon overall • Higher customer retention was neutral for Delivery and unfavorable for Generation and Exelon Overall 31
  • 33. Consolidated – Key Assumptions 2004A 2005E 2006E (1) 93.5 93.9 92.9 Nuclear Capacity Factor (%) 202,599 220,700 193,700 Total Genco Sales Ex Trading (GWhs) 110,465 119,400 118,700 Total Sales to Energy Delivery (GWhs) 92,134 101,200 75,000 Total Market and Retail Sales (GWhs) Volume Retention (%) 88 94 95 PECO 77 79 76 ComEd (2) Delivery Growth (%) 3.8 0.2 2.6 PECO 3.3 1.2 2.2 ComEd Elec. Wholesale Mkt. ATC Price ($/MWh) 31.15 40.00 43.00 PJM Midwest (NiHUB) 42.34 49.00 54.00 PJM Mid-Atlantic (West Hub) 36.5 37.5 37.5 Effective Tax Rate (%) Note: Data for Exelon stand-alone A = Actual; E = Estimate; ATC = Around the clock (1) Excludes Salem (2) Weather Normalized Source: 8/5/05 Exelon Investor Conference 32
  • 34. Portfolio Sensitivities for Genco 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 Power -$1.00 ATC* ATC* Sep to Dec 2005 $4 ($3) Calendar 2006 $28 ($27) * ATC = Around the Clock 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 Source: 8/5/05 Exelon Investor Conference 33
  • 35. Deploying Our Cash $5.0 $4.0 $3.0 Aug-04 Projected Free Cash Flow 4.0 $2.0 3.8 Net Cash from Operations $1.0 $ Billions $0.0 Transition Debt Retirements (0.8) (0.9) ($1.0) (0.5) Nuclear Fuel (0.5) (0.6) (0.6) Genco CapEx ($2.0) Current Projected (1.0) Free Cash Flow (1.1) EED CapEx ($3.0) (0.1) Corp. CapEx (1.1) ($4.0) (1.1) Dividends ($5.0) 2005E 2006E Our current cash flow forecast reflects increased investments in the core business – mainly on the regulated side 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. Source: 8/5/05 Exelon Investor Conference 34
  • 36. Exelon Consolidated GAAP Earnings to Adjusted (non-GAAP) Operating Earnings – YTD through Sept. (in Millions, except EPS) A B C D E F YTD 2005 YTD 2004 Operating Operating GAAP Adjustments Earnings GAAP Adjustments Earnings Line Operating revenues $ 11,519 $ - $ 11,519 $ 10,821 $ (248) (e) $ 10,573 1 Fuel & purchased power 4,012 152 (a) 4,164 3,781 (187) (a),(e) 3,594 2 Revenue Net Fuel 7,507 (152) 7,355 7,040 (61) 6,979 3 Operating & maintenance 2,804 (76) (b),(c),(h) 2,728 2,696 (137) (b),(e),(h),(j) 2,559 4 Depreciation & amortization 1,003 (56) (b),(c) 947 974 (40) (b),(e) 934 5 548 (9) (e) 539 Taxes other than income 560 - 560 6 4,218 (186) 4,032 Total operating expenses 4,367 (132) 4,235 7 2,822 125 2,947 Operating income 3,140 (20) 3,120 8 (633) 19 (b),(e) (614) Interest expense (615) 11 (b) (604) 9 (97) 48 (b) (49) Equity in Earnings (107) 86 (b) (21) 10 43 16 (e),(i) 59 Other, net 108 - 108 11 2,135 208 2,343 Income from continuing operations, pre-tax 2,526 77 2,603 12 661 230 (a),(b),(e),(h),(i),(j) 891 Income taxes 779 220 (a),(b),(c),(h) 999 13 1,477 (22) 1,455 Income from continuing operations 1,747 (143) 1,604 14 1 - 1 (g) Gains (losses) from discontinued operations 13 (16) (d) (3) 15 23 (32) (f) (9) Cumulative effect of a change in accounting - - - 16 $ 1,501 $ (54) $ 1,447 Net income $ 1,760 $ (159) $ 1,601 17 $ 2.25 $ 2.17 Earnings per share (diluted) $ 2.60 $ 2.37 18 Adjustment to exclude the mark-to-market impact of Exelon's non-trading activities (primarily at Generation). (a) Adjustment to exclude the financial impact of Exelon's investments in synthetic fuel-producing facilities. (b) (c) Adjustment to exclude costs associated with Exelon's anticipated merger with Public Service Enterprise Group Inc. (d) Adjustment to exclude the 2005 financial impact of Generation's investment in Sithe Energies, Inc. (e) Adjustment to exclude the 2004 financial impact of Boston Generating, LLC. Adjustment for the cumulative effect of adopting FIN No. 46-R. (f) Includes the 2004 financial impact of Enterprises. (g) (h) Adjustment to exclude severance charges. (i) Adjustment to exclude the losses associated with debt retirements at ComEd. Adjustment for a settlement gain related to the storage of spent nuclear fuel. (j) Note: Items may not add due to rounding. 35
  • 37. Reconciliation of 2004 GAAP Reported and Adjusted (non-GAAP) Operating Earnings per Diluted Share 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 36
  • 38. 2005/2006 Earnings Guidance 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, certain severance costs, the cumulative effect of the adoption of FIN 47 – “Accounting for Conditional Asset Retirement Obligations,” and costs associated with the proposed merger with PSEG. The outlook for 2006 adjusted (non-GAAP) operating earnings is Exelon stand-alone and excludes unrealized mark-to-market adjustments from non-trading activities, income resulting from investments in synthetic fuel-producing facilities and costs associated with the proposed merger. These estimates do not include any impact of future changes to GAAP. Earnings guidance is based on the assumption of normal weather. 37
  • 39. 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 38
  • 40. 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 Preferred Securities of Subsidiaries Adjusted Book Debt Total Adjusted Capitalization Note: FFO and Debt related to non-recourse debt are excluded from the calculations.