| EEI International Utility Conference London, UK February 19-22, 2006 Exelon Corporation Public Service Enterprise Group |
| 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 (a) the Exelon Companies' 2005 Annual Report on Form 10-K-ITEM 1A. Risk Factors, (b) the Exelon Companies' 2005 Annual Report on Form 10-K-ITEM 8. Financial Statements and Supplementary Data: Exelon-Note 20, ComEd-Note 17, PECO-Note 15 and Generation-Note 17, and (c) other factors discussed in filings with the 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. |
| Key Messages Exelon Overview PSEG Overview EEG Merger Overview Additional Information Agenda |
| Continued strong stand-alone performance at both Exelon and PSEG Value-added, operationally-driven merger Progressing towards close in second or third quarter 2006 Uniquely positioned generation business Large, low-cost, low-emissions, exceptionally well-run nuclear fleet Upside from end of below-market contracts in Illinois and Pennsylvania and re-pricing of forward market sales Improving power market fundamentals Stable growth delivery businesses with improving operations in three major metropolitan areas Strong balance sheet and financial discipline Experienced management team Key Messages |
| Exelon Overview |
| (1) Includes long-term contracts Note: Data based on results reported through 2/14/06 Sources: Company reports What Is Exelon? |
| Exelon Overview (1) At 12/31/05; includes long-term contracts and investments in two facilities in Mexico of 230 MWs Note: See presentation appendix for adjusted (non-GAAP) operating reconciliations to GAAP Pennsylvania Utility Illinois Utility Nuclear Generation Fossil Generation Power Marketing Nuclear Capacity: 16,856 MW Total Capacity: 33,520 MW(1) ~50% of Operating Earnings Customers Electric: 3.7M 1.5M Gas: - 0.5M ComEd & PECO each contribute ~25% of Operating Earnings Traditional T&D Regional Wholesale Energy 2006E Operating Earnings: $2.0-$2.2B 2006 EPS Guidance: $3.00-$3.30 Assets (12/31/05): $42.4B |
| 11,300 MW 5,291 MW 16,591 MW 8,772 MW Midwest Owned Generation: Contracted Gen: Total Generation: ComEd PPA Avg Load: 2,299 MW 2,900 MW 5,199 MW ERCOT/South Owned Generation: Contracted Gen: Total Generation: 10,958 MW 4,414 MW Mid-Atlantic Owned Generation:: PECO PPA Avg Load: 25,099 MW 8,191 MW 33,290 MW Total Owned Generation: Contracted Gen: Total Generation: Generating Plants %MW Nuclear 50 Hydro 5 Coal 9 Intermediate 7 Peaker 29 Exelon Energy Delivery Retail Customers 3.7M Electric in Northern Illinois 1.5M Electric and 0.5M Gas in Southeastern Pennsylvania 542 MW New England Owned Generation: Note: Megawatts based on Exelon Generation's ownership as of 12/31/05; excludes investments in two facilities in Mexico of 230 MWs Exelon is positioned as a multi-regional, baseload producer with merchant activity in the South Our Regional Positions |
| Looking Back: 2000 - 2005 Exelon had 9.9% average annual operating earnings per share growth driven by: PECO / Unicom merger Improved operations Core growth in retail delivery volumes Effective commodity risk management Cost management initiatives Debt reduction and refinancings Despite: Retail rate freeze Merchant power overbuild Volatile wholesale prices Note: See presentation appendix for GAAP EPS reconciliation |
| 2004A 2005A 2006 Estimate 2007 East 2.78 3.09 3 0.24 $2.78 $3.10 $3.00-$3.30 + Generation Margins + Weather + Load Growth - - Other Exelon's EPS Drivers: 2004 - 2007 + Generation Margins + Load Growth - - Weather - - Higher O&M + End of Illinois Transition Period + PECO Generation Rate + Load Growth - Inflation Note: See presentation appendix for adjusted (non-GAAP) operating EPS reconciliations to GAAP 2005 Guidance: $3.00 - $3.15 Strong earnings growth will continue in 2006 and accelerate in 2007 Adjusted (non-GAAP) operating EPS Guidance |
| ComEd becomes a pure wires business Returns determined through traditional regulatory processes Received Illinois Commerce Commission (ICC) approval of reverse auction with energy cost pass through - - Rate increase expected on delivery services tariff (DST) Exelon Generation gets a market price for all its Midwest production - - Approximately 90 TWh nuclear and 10 TWh coal - - About 2/3 of which is currently supplied to ComEd at a discount to today's market price Composition of earnings shifts from ComEd to Generation ComEd is willing to work with stakeholders to mitigate the potential customer impacts of transitioning to market prices for generation Net Impact on earnings is expected to be positive for Exelon overall ComEd Genco Exelon Generation Margin - + + DST + N/A + Net Earnings Impact - + + End of Illinois Transition Period |
| 2002 2003 2004 2005 2006E 2007E Generation 0.24 0.3 0.33 0.5 0.52 0.73 ComEd 0.47 0.45 0.42 0.25 0.26 0.12 PECO 0.29 0.25 0.25 0.25 0.22 0.15 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 Composition of Operating Earnings * Based on Thomson First Call consensus EPS estimate of $4.32 as of 2/14/06 for Exelon stand-alone |
| PSEG Overview |
| PSEG Overview Electric Customers: 2.1M Gas Customers: 1.7M Nuclear Capacity: 3,484 MW Total Capacity: 14,549 MW Traditional T&D Leveraged Leases 2006E Operating Earnings(1): $875M - $950M 2006 EPS Guidance: $3.45 - $3.75 Assets (as of 12/31/05): $ 29.9B Domestic/Int'l Energy Regional Wholesale Energy (1) Includes the parent impact of $(70-80)M; Excludes Merger-related costs 2005 Results: $347 M $418 M $196 M 2006 Range: $315M - $335M $475M - $525M $155M - $175M |
| 2005 Actual Markets Operations New Assets Leases Other 2006 Guidance 2007 2008 West 890 890 1049 1010 966 914 0 0 0 Seminole 159 48 87 33 17 918 1000 1100 NDT 35 Weather Driven by Power Recontracting at Higher Commodity Prices $3.45 to $3.75 $3.65 PSEG Stand-Alone 2006 Earnings Guidance More than 10% Growth Each Year 244M Avg. Shares 253M Avg. Shares NDT Normal Weather NDT = nuclear decommissioning trust |
| 2006 Key Events Natural Gas Price Impact Longer-term Benefits Liquidity Customer Impact Dampened - BGS: 3-year contracts - BGSS: storage and hedges Balance Sheet Liquidity - $2.7B as of 12/31/05 Regulatory Gas Rate Case - $133M increase requested - $55M Depreciation - $1.96B Utility Rate Base - 11% ROE $64M Depreciation Credit Expired 12/31/05 BPU Requested 3/31/06 Results Operations Hope Creek Refueling Salem 2 Refueling Est. 91% capacity factor Linden on-line |
| 20,000 4,000 8,000 12,000 16,000 2002 2003 2004 2005 2006 2007 2008 1 Year 170 Traunches 10 months 104 Traunches 34 months 51 Tranches 1 Year 50 Traunches 3 Years 51 Traunches 2006 FP Auction Load 54 Traunches 2005 FP Auction Load 50 Traunches 2007 FP Auction Load (projected) Total NJ BGS FP Load (MW) NJ BGS Auction Structure BGS Auction Structure |
| BGS Auction Results 2003 Auction 2004 Auction 2005 Auction 2006 Auction East 34 37 45.14 67.7 West 21.59 18.05 20.77 34.51 $33 - $34 $36 - $37 $55.59 (34 Month NJ Avg.) $55.05 (36 Month NJ Avg.) $65.91 (36 Month NJ Avg.) $44 - $46 Transmission Ancillary services Load shape Congestion Risk premium Capacity ~ $21 ~ $18 ~ $21 RTC Forward Energy Cost RTC = round the clock $102.21 (36 Month NJ Avg.) $67 - $70 ~ $32 |
| EEG Merger Overview Generation PEG: EXC: (MWs) Exelon PSEG EEG U.S. Rank Nuclear 16,751 3,484 20,235 1 TOTAL MW's (1) 34,457 17,018 51,475 1 Elec. Customers 5,200,000 2,100,000 7,300,000 1 Gas Customers 460,000 1,700,000 2,160,000 7 (1) Year-end 2004; Generation numbers include long-term contracts. |
| A "Win-Win"Combination Combined Company Enhanced earnings Regulatory and market diversity Increased operating flexibility Strong, stable cash flow with commitment to solid investment grade ratings Experienced management team PSEG Brings Excellence in transmission and distribution operations Expertise in BGS auction development and participation Strong gas LDC experience Exelon Brings Premier nuclear operation expertise Broad platform for earnings and cash flow growth Large merger integration success BGS = Basic Generation Service LDC = local distribution company |
| Market Concentration Mitigation 7/1/05 - FERC issued merger approval order Working with DOJ and NJ BPU 4,000 MW Fossil Divestiture Must complete within 12 months of merger closing Peaking: 1,200 MW High Mid Merit: 900 MW CCGT: 1,200 MW Coal: 700 MW Merrill Lynch advising on sale 2,600 MW Nuclear Virtual Divestiture MDI selected as auction manager LD product sold as "Eastern Nuclear Generation Aggregate (ENGA)" PJM Market Monitor 2/9/06 report concluded that proposed 6,600 MW divestiture passes his market concentration screens, that are based on the DOJ merger policy guidelines, for the aggregate energy market Combined Cycle 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. LD product = liquidated damages product |
| Corporate, Business Services 0.28 Trading 0.13 Fossil 0.1 Nuclear 0.29 Nuclear Production 0.2 20% ~$70m 29% ~$100m 28% ~$100m Trading Genco Corp/ Fossil Corporate, Business Services Nuclear Production Improvements Corp/BSC 0.63 Utility 0.37 43% ~$65m T&D Operations 57% ~$85m Corporate, Business Services 13% ~$45m 10% ~$35m Nuclear Cost Reduction Note: Regulated synergies reflect February 4, 2005 testimony. Unregulated: Exelon Generation Regulated: Exelon Energy Delivery (70% = $350 million) (30% = $150 million) $500 Million of Synergies Beyond Year 1 Synergies are mostly unregulated and backed-up by detailed execution plans |
| 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 Policy Act of 2005 do not apply Department of Justice Hart-Scott-Rodino review The waiting period expired September 1 DOJ review continues, but is not expected to delay closing Pennsylvania PA Public Utility Commission approved settlement on 1/27/06 New Jersey Schedule revised; hearings expected to conclude March 27 Final NJ Board of Public Utilities' decision expected later; merger close anticipated in the third quarter 2006, unless we settle earlier |
| Dec 2004 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Announce Transaction 12/20/04 Shareholder Approvals 7/05 FERC, NJBPU, PAPUC, ICC Regulatory Filings 2/4/05 File Joint Proxy Statement 2/10/05 Work to Secure Regulatory Approvals (FERC, DOJ, ICC*, PA PUC, NJ BPU, and others) Develop Transition Implementation Plans CLOSE TRANSACTION Beginning 1/17/05, Implement Nuclear Operating Services Agreement Q2-Q3 2006 * Notice filing only FERC Approval Order 7/1/05 Respond to DOJ 2nd Request NJ BPU Hearings Scheduled NJ BPU Final Decision Expected unless Settled Earlier PA PUC Settlement Approval 1/27/06 Anticipated Merger Timeline NJ Settlement Discussions Scheduled NJ Settlement Discussions Scheduled |
| Unmatched scale and scope through merger Strong balance sheet and financial discipline 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 Experienced management team EE&G Value Proposition |
| Appendix - Additional Information |
| Expected EPS Drivers Guidance: $3.00 - $3.30 Notes: For reconciliation to GAAP reported EPS, see 4Q 05 earnings release attachments within Exhibit 99 of Form 8-K filed 1/25/06. 2006 Adjusted (non-GAAP) Operating EPS - Stand-alone 2005A Weather Generating RNF Load Growth O&M Outages Amort. / Depr. Interest Expense Other 2006 Budget Invisible dataset 0 2.9755 2.9755 3.3289 3.236732 3.222023 3.192536 3.131035 3.131035 0 Green 3.0999 0.1245 0.353419011 0.092167645 0.186595322 0.010930095 0.029486914 0.061501258 0.018965 3.15 2006 Estimate Weather Generation RNF Interest Expense, Net All Other 2005 Actual Higher generation margins and normal load growth, partially offset by higher O&M costs, will continue to drive earnings growth in 2006 Nuclear Refueling Outages Risks and Opportunities +/- Nuclear Output +/- Weather +/- Power Prices +/- Natural Gas Prices +/- Economy $3.00 - $3.30 Depr./ Amort. Inflation: ($0.10) Pension & Benefits: ($0.05) Option Expense: ($0.04) Load Growth O&M |
| Exelon Consolidated: FFO / Interest 6.1x BBB 4.5x - 6.5x FFO / Debt 31% 30% - 45% Debt Ratio 51%(3) Generation: FFO / Interest 12.7x BBB+ 5.5x - 7.5x FFO / Debt 92% 40% - 55% Debt Ratio 31% ComEd: FFO / Interest 3.9x A- 3.5x - 4.2x FFO / Debt 18% 20% - 28% Debt Ratio 37%(3) PECO: FFO / Interest 5.8x A- 3.5x - 4.2 x FFO / Debt 23% 20% - 28% Debt Ratio 51% (Stand-alone) Notes: Exelon consolidated, ComEd and PECO metrics exclude securitization debt. See presentation appendix for FFO (Funds from Operations)/Interest and FFO/Debt reconciliations to GAAP. (1) Senior unsecured ratings for Exelon and Generation and senior secured ratings for ComEd and PECO; (2) Based on S&P Business Profiles 7, 8 and 4 for Exelon, Generation, and ComEd and PECO, respectively; (3) Reflects $1.2 billion ComEd goodwill write off in 2005 Exelon's Balance Sheet is strong "A" Target Range (2) Projected 2006 Key Credit Measures S&P Credit Ratings(1) |
| Moving Illinois Forward Summer 2004 - Illinois Commerce Commission (ICC) Stakeholder Workshops Consensus developed around the use of a competitive procurement process for establishing market-based rates post 2006 ICC staff report recommended a reverse auction (like New Jersey's) as the best available competitive procurement process ComEd Procurement Case In January 2006, the ICC approved a reverse-auction competitive bidding process; the first auction is scheduled to take place in fall 2006 Auction patterned after successful process in NJ and will result in a reliable power supply at the lowest available market price To mitigate the impact on residential customers, ComEd proposed a "cap and deferral" plan to keep residential rates at or below 1995 levels through 2009 ComEd Delivery Case Traditional rate case filed 8/05 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 |
| 33% of load 33% of load 33% of load 3 yrs. + 5 mos. 3 yrs. 3 yrs. 3 yrs. 2 yrs. + 5 mos. 3 yrs. 3 yrs. 3 yrs. 17 mos. 3 yrs. 3 yrs. 3 yrs. 3 yrs. >> 3 yrs.>> Calendar Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 PJM Planning Year (June 1- May 31) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Transitional contracts shown in black. 17 mos. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. 1 yr. CPP-B CPP-A (for customers < 3 MW) Term Structures for Fixed Price Auctions ComEd Energy Procurement Plan Notes: CPP-A is the auction for the annual fixed price product. It is the default service for customers between 400 KW and 3 MW. CPP-B is the auction for the blended fixed price products (blended 3-year contracts) applicable to residential and small commercial customers below 400 KW. |
| Targeted capital investment and sound operating fundamentals driving fleet efficiency and reliability Market-driven investments in plant improvements that increase unit profitability Material condition improvement resulting in improved unit reliability, heat rate and capacity Capitalizing on market opportunities through improved operating flexibility and market responsiveness Application of Management Model has resulted in improved operations; will provide similar results in the larger PSEG fossil fleet Exelon Power is well positioned to capitalize on market opportunities Exelon Power Performance - Reliability |
| Nuclear Performance - Production Sustained nuclear production reliability Continued growth in generation output Consistently high capacity factors Continued excellence in refueling outage performance Exelon Nuclear's sustained reliability is a competitive advantage Data sources: Nucleonics Week, Electric Utility Cost Group. Exelon data excludes Salem |
| Exelon capitalizes on its nuclear cost advantage Consistent improvement in production cost Industry leader in production cost by a substantial margin The size and scale of the fleet enables low-cost generation Exelon's low-cost nuclear generation is a competitive advantage Data source: Electric Utility Cost Group Nuclear Performance - Cost |
| 2004 2005 2006 2007 2008 2009 2010 Contracted 10700 8991 6923 8456 7342 3629 2520 Flexibilities 1810 3517 1707 1571 186 70 Demand 8437 11587 8472 10027 7528 9196 7393 Uranium market prices have increased, but Exelon is managing its portfolio Reduced uranium consumption by 25% Contracting strategy protects us from increases through 2008 Uranium is a small component of total production cost Expect long-term fundamentals in $20-25 range due to new uranium production Exelon Nuclear is managing fuel costs Nuclear Performance - Fuel Costs |
| PSEG/Nuclear Operating Services Agreement Nuclear Operating Services Agreement with Salem/Hope Creek is meeting or exceeding expectations Strong production performance Combined site capacity factor of 89.1% for 2005 Highest combined site generation ever Two strong refueling outages with major material condition work Salem 2 spring refueling - unit's best ever Salem 1 fall refueling set world record for shortest refueling with reactor head replacement Extensive investment in long-standing equipment issues Maintenance backlogs significantly reduced Financial performance exceeded expectations due to rigorous cost controls Effective site transition to Exelon Nuclear Management Model and organization structure Completed 25 functional area assessments as basis for implementation Site still faces challenges in sustainability of performance |
| GAAP EPS Reconciliation 2000-2002 |
| Reconciliation of GAAP Reported and Adjusted (non-GAAP) Operating Earnings per Diluted Share GAAP EPS Reconciliation 2003-2005 |
| 2006 Exelon Earnings Guidance The outlook for 2006 adjusted (non-GAAP) operating earnings is Exelon stand-alone and excludes unrealized mark-to-market adjustments from non-trading activities, income resulting from investments in synthetic fuel-producing facilities, significant impairments of intangible assets, certain severance costs, and costs associated with the proposed merger with PSEG. These estimates do not include any impact of future changes to GAAP. Earnings guidance is based on the assumption of normal weather. |
| Attractive Pricing Environment PJM Western Hub (RTC) Forward Prices and NYMEX Natural Gas (Henry Hub) BGS Auction Result: NJ Avg -Approx ($/MWh ) $33 - $34 $36 - $37 $44 - $46 $67 - $70 PJM West RTC ($/MWh) NYMEX - Henry Hub ($/MBTU) $55 $55 $66 $102 $5.15 - $5.35 $5.25 - $5.40 $6.50 - $6.65 $9.50 - $10.00 |
| BGS and Long-Term Contracts 0% 20% 40% 60% 80% 100% 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 % of Nuclear and Coal Generation Generation output not under contract Other term energy contracts 2003 BGS United Illuminating 2004 BGS 2005 BGS PSEG Power Term Contracts 85 - 90% 65 - 75% 35 - 50% Hedge positions to be updated in 2005 10-K filing % Hedged: |
| Key Merger Transaction Terms Offer Price: 1.225 shares of Exelon per PSEG share Ownership: 68% Exelon shareholders 32% PSEG shareholders Governance: John W. Rowe to be CEO E. James Ferland to be non-executive Chairman 18 Board members - 12 nominated by Exelon - 6 nominated by PSEG Nuclear Agreement: Operating Services Contract started 1/05 Approvals: Shareholders, Federal and State Regulatory |
| Source: Cambridge Energy Research Associates (CERA); 2003 data U.S. Electric Value Chain |
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 Interest Coverage | ||
FFO + Adjusted Interest | ||
| Net Interest Expense (Before AFUDC & Cap Interest) | ||
| - Trust-Preferred Interest Expense | ||
| - Transition Bond Interest Expense | ||
+ 10% of PV of Operating Leases | ||
FFO Debt Coverage | ||
FFO | ||
| Debt: | ||
| LTD STD - - Transition Bond Principal Balance Add debt equivalents: | ||
| + A/R Financing | ||
+ PV of Operating Leases | ||
| (1) Use average of prior year and current year adjusted debt balance | ||
Debt to Total Cap | ||
Adjusted Book Debt | ||
| Debt: | ||
LTD STD - - Transition Bond Principal Balance | ||
| Capitalization: | ||
| Total Shareholders’ Equity | ||
| Preferred Securities of Subsidiaries | ||
Adjusted Book Debt | ||
| Note: FFO and Debt related to non-recourse debt are excluded from the calculations. |