UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
November 5, 2007
Date of Report (Date of earliest event reported)
| Commission File |
Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS Employer | ||
| 1-16169 | EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398 |
23-2990190 | ||
| 333-85496 | EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 |
23-3064219 | ||
| 1-1839 | COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 |
36-0938600 | ||
| 000-16844 |
PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 |
23-0970240 | ||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Section 7—Regulation FD
| Item 7.01. | Regulation FD Disclosure. |
On November 5-6, 2007, Exelon Corporation (Exelon) will participate in the Edison Electric Institute Conference. Attached as Exhibit 99.1 to this Current Report on Form 8-K are the presentation slides and handouts to be used at the conference.
Section 9—Financial Statements and Exhibits
| Item 9.01. | Financial Statements and Exhibits. |
| (d) | Exhibits. |
| Exhibit No. | Description | |
| 99.1 | Presentation Slides and Handouts |
* * * * *
This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company and PECO Energy Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2006 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2007 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| EXELON CORPORATION |
| EXELON GENERATION COMPANY, LLC |
| /s/ John F. Young |
| John F. Young |
| Executive Vice President, Finance and Markets and Chief Financial Officer |
| Exelon Corporation |
| COMMONWEALTH EDISON COMPANY |
| /s/ Robert K. McDonald |
| Robert K. McDonald |
| Senior Vice President, Chief Financial Officer, |
| Treasurer and Chief Risk Officer |
| Commonwealth Edison Company |
| PECO ENERGY COMPANY |
| /s/ Phillip S. Barnett |
| Phillip S. Barnett |
| Senior Vice President and Chief Financial Officer |
| PECO Energy Company |
November 5, 2007
EXHIBIT INDEX
| Exhibit No. | Description | |
| 99.1 | Presentation Slides and Handouts |
 Value
Driven Edison Electric Institute Conference Orlando, Florida November 5-6, 2007 John F. Young Executive Vice President & Chief Financial Officer Exhibit 99.1 |
 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 to
differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2006 Annual Report on Form 10-K in
(a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations and (c) ITEM 8.
Financial Statements and Supplementary Data: Note 18; (2) Exelon’s Third Quarter 2007 Quarterly Report on Form 10-Q in (a) Part II, Other Information,
ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 13; and (3) other factors discussed in filings with the Securities and Exchange Commission by Exelon
Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, and PECO Energy Company (Companies). Readers are cautioned not to place undue reliance on these
forward-looking statements, which apply only as of the date of this
presentation. None of the Companies undertakes any obligation to
publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. This presentation includes references to adjusted (non-GAAP) operating earnings that
exclude the impact of certain factors. We believe that these adjusted
operating earnings are representative of the underlying operational results
of the company. Please refer to the Appendix to the presentation for a reconciliation of adjusted (non-GAAP) operating earnings to GAAP earnings.
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 3 Agenda Industry & Market Dynamics PECO ComEd Exelon Generation Exelon Appendix • O&M and Capital Expenditure Expectations • Pennsylvania Legislative/Regulatory Snapshot • ComEd Transmission Settlement and Distribution Case Summaries • Generation Portfolio Characteristics and Hedging Targets • Required Break-Even Cost by Technology (Illustrative) • Nuclear Fleet Details • Exelon and Climate Change Today’s discussion will focus on Exelon’s five-year outlook
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      4 Energy dependency / geopolitical concerns Declining US reserve margins Environmental / climate change concerns Continued strong global growth in energy consumption Continued high fossil fuel prices Massive capital investment Increasing cost of new build Technology improvements Increasing heat rates Increasing capacity prices With Numerous Forces Driving the Industry… Political / regulatory pressures >80% EPS from unregulated generation Largest, lowest-cost nuclear fleet in competitive markets Complementary and flexible fossil and hydro fleet Executing regulatory recovery plan at ComEd Managing transition to competitive markets in Pennsylvania Increasingly strong cash flows and balance sheet Exelon Position Macro Trends Market Response |
 5 PECO ExGen ComEd PECO ExGen Operating EPS (3) : $2.41 Operating EPS Guidance (3) : $4.15 – $4.30 (1) Total Shareholder Return for the period 12/31/01 – 10/31/07. (2) ~65% EPS growth assumes $10/tonne carbon and equates to ~10%+ CAGR; ~13%+ CAGR assuming
$20/tonne carbon; 1 tonne = 2,205 lbs. (3) See Appendix for
reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. ExGen ComEd 2002 2007 2012 …Exelon Is Uniquely Positioned for Continued Strong Value Creation ~10%+ Compound Annual Growth Rate in EPS from 2007 to 2012
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 6 |
   7 4.2 4.3 5.0 2.7 2.0 Competitive Transition Charge (CTC) Rate Base (Transmission, Distribution & Gas) PECO – Moving Forward (1) Rate base details provided in Appendix. (2) 2007 Operating Earnings Guidance; see Appendix for reconciliation of adjusted
(non-GAAP) operating EPS to GAAP EPS. (3) Provided solely to illustrate possible future outcomes that are based on a number of
different assumptions, all of which are subject to uncertainties and should not be relied upon as a forecast of future results. Transitioning through an orderly structure to market-based rates • Increasing CTC amortization results in declining rate base and net income through 2010 Working proactively with the Governor, Legislature, and PAPUC for post- transition rates and structure Supporting plans to implement energy efficiency and renewable programs Preparing power procurement filing for 2008 to address post-transition plan beginning in 2011 Net Income ROE Equity $435 – $470M Not applicable due to transition rate structure $360 – $400M 6.9 6.3 5.0 ~$250 – $270M ~10 – 11% ~50% 2007 (Guidance) (2) 2008 (Preliminary) 2012 (Illustrative) (3) PECO provides a predictable source of earnings to Exelon through the remainder of the transition period Actively Engaged in Transition Average Annual Rate Base (1) ($ in Billions) |
 8 |
   9 6.0 6.6 8.4 1.8 2.0 2.3 Transmission Distribution ComEd – Moving Forward (1) 2007 Operating Earnings Guidance; see Appendix for reconciliation of adjusted
(non-GAAP) operating EPS to GAAP EPS. (2) Equity based on definition provided in most recent ICC distribution rate case order (book equity less goodwill). Projected book equity ratio in 2007 is 58%. (3) Provided solely to illustrate possible future outcomes that are based on a number of
different assumptions, all of which are subject to uncertainties and should not be relied upon as a forecast of future results. (4) Assumes full $361M revenue increase granted in current distribution rate case.
Executing Regulatory Recovery Plan Net Income ROE Equity (2) $220M – $260M (4) $130M – $165M ~5.5 – 6.5% ~3.8 – 4.8% 45% 44% After 2007, ComEd’s earnings are expected to increase as regulatory lag is reduced over time through regular rate requests, putting ComEd on a path toward appropriate
returns Implementing progressive formula transmission rate upon FERC approval of settlement Supporting recently filed distribution rate case Actively promoting/implementing efficiency, renewable energy, and demand-side management programs Studying innovative future test year approach for distribution rate filing in 2009 7.8 8.6 10.7 Average Annual Rate Base ($ in Billions) ~$490M – $530M ~10 – 11% ~45% 2007 (Guidance) (1) 2008 (Preliminary) 2012 (Illustrative) (3) |
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    11 Average Capacity Factor Large, low-cost, low-emissions, exceptionally well-run nuclear fleet Complementary and flexible fossil and hydro fleet Improving power market fundamentals (commodity prices, heat rates, and capacity values) End of below-market contracts in Pennsylvania beginning 2011 Potential carbon restrictions Value Proposition Exelon Generation Continue to focus on operating excellence, cost management, and market discipline Support competitive markets Pursue nuclear & hydro plant relicensing and strategic investment in material condition Maintain industry-leading talent Protect Value Pursue nuclear plant uprates (~200MW by 2012) and investigate potential for more Pursue nuclear Construction and Operating License in Texas and Mountain Creek expansion Capture increased value of low-carbon generation portfolio Grow Value Exelon Generation is the premier unregulated generation company – positioned to capture market opportunities and manage risk z |
 12 World-Class Nuclear Operator 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Exelon Industry Note: Exelon data prior to 2000 represent ComEd-only nuclear fleet. Sources: Platt’s, Nuclear News, Nuclear Energy Institute and Energy Information Administration (Department of Energy). 65 70 75 80 85 90 95 100 Operator (# of Reactors) Range 5-Year Average EXC 93.2% Average Capacity Factor Range of Fleet 2-Yr Avg Capacity Factor (2002-2006) Sustained production excellence |
 13 -15% -10% -5% 0% 5% 10% 15% 20% 25% 30% 2007 2008 2009 2010 2011 2012 Reserve Margins Declining Natural Gas Prices Remaining High PJM-West PJM-East NI-Hub ERCOT $5 $6 $7 $8 $9 $10 2008 2010 2012 2014 2016 2018 2020 NYMEX Positively Exposed to Market Dynamics Note: Illustrative estimate. Overnight, all-in capital cost without interest
during construction. 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 5 10 15 20 25 30 35 40 45 0 5 10 15 20 25 30 EIA Carbon Case 2010: $31/tonne Europe Carbon-Trading 2012: $35.50/tonne Carbon Credit ($/Tonne) Carbon Legislation Progressing Lieberman-Warner Possible $20 to $40/tonne Bingaman-Specter 2012: $12/tonne Various 3rd party estimates Construction Costs Escalating Note: Refer to the Appendix for additional information. New Generation Installed Cost Combined Cycle Gas Turbine Coal Nuclear 0 500 1,000 1,500 2,000 2,500 3,000 2006 2007 2006 2007 2006 2007 |
 14 Long-Run Marginal Cost of Electricity IGCC – No CO2 Recapture Pulverized Coal CCGT Nuclear Excluding energy efficiency, nuclear is the least expensive generation option in a carbon-constrained environment CCGT = Combined Cycle Gas Turbine; IGCC = Integrated Gasification Combined Cycle
0 20 40 60 80 100 120 140 0 5 10 15 20 25 30 35 40 45 50 CO2 Price ($/Metric Ton) |
 15 Exelon Generation – Long-Term Value Exelon Generation is poised for significant earnings growth driven by improving market
fundamentals, the end of the Pennsylvania transition period, and carbon legislation 2007 Guidance (1) 2012 2008 (1) 2007 Operating Earnings Guidance; see Appendix for reconciliation of adjusted
(non-GAAP) operating EPS to GAAP EPS. $2,320M - $2,385M 2009 – 2012 Earnings Drivers End of PECO PPA (2011+) Carbon (2012+) Market conditions - Heat rate - Capacity prices - New build costs Nuclear uprates Higher O&M costs Higher nuclear fuel costs Higher interest and depreciation expense 2008 Earnings Drivers Market conditions - Capacity prices - Marginal losses More nuclear outages Higher nuclear fuel costs Higher O&M costs State Line buyout Higher interest and depreciation expense |
 16 125 127 129 131 133 135 137 139 141 143 145 2004 2005 2006 2007 2008 2009 2010 2011 2012 7 8 9 10 11 12 13 Based on the refueling cycle, we will conduct 12 refueling outages in 2008, versus 9 in 2007, and 10 to 11 in a typical year Impact of Refueling Outages Note: Net nuclear generation data based on ownership interest; includes
Salem. 18 or 24 months Duration: ~24 days Nuclear Refueling Cycle 2008 is an exception: • Salem steam generator replacement • 3 more outages than 2007 • ~2,600 GWh less than 2007 $100-$110M negative after-tax impact 2008 Refueling Outage Impact Refueling Outage Duration Nuclear Output 0 5 10 15 20 25 30 35 40 45 2000 2001 2002 2003 2004 2005 2006 Sept '07 YTD Exelon Industry Actual Target Estimate |
 17 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 2007 2008 2009 2010 2011 2012 Effectively Managing Nuclear Fuel Costs Enrichment 38% Fabrication 17% Nuclear Waste Fund 23% Tax/Interest 2% Conversion 3% Uranium 17% Components of Fuel Expense in 2007 0 200 400 600 800 1,000 1,200 1,400 2007 2008 2009 2010 2011 2012 Nuclear Fuel Expense (Amortization + Spent Fuel) Nuclear Fuel Capex Projected Total Nuclear Fuel Spend Projected Exelon Average Uranium Cost vs. Market Projected Exelon Uranium Demand 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2007 2008 2009 2010 2011 2012 Exelon Average Reload Price Projected Market Price (Term) Note: Excludes costs reimbursed under the settlement agreement with the DOE. Market source: UxC composite forecasts. Refer to Appendix for uranium price sensitivities. 2007 – 2011: 100% hedged in volume 2012: ~40% hedged in volume All charts exclude Salem, except Projected Total Nuclear Fuel Spend.
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 18 2008 “Open” EBITDA 2008 EBITDA 2008 Open EBITDA (No Carbon) $ Millions ~$4,100 ~$3,900 2007 EBITDA (2) Un-hedged (“Open”) EBITDA plus upside from energy, capacity, and carbon
drives Exelon Generation’s value (1) Un-hedged EBITDA assumes that existing hedges (including the PECO load, Illinois
auction load, ComEd financial swap, and other sales) are priced at market prices as of 7/31/07. (2) Refer to the Appendix for a reconciliation of Net Income to EBITDA. (3) 1 tonne = 2,205 lbs. ~$5,350 Hedged – 2008 Un-Hedged – 2008 (1) Hedged – 2007 169.20 Eastern MAAC Capacity Price ($/MW-day) 82.30 Rest-of-Market Capacity Price ($/MW-day) 5.6 NI-Hub Implied Heat Rate (mmBtu/MWh) 6.6 PJM W-Hub Implied Heat Rate (mmBtu/MWh) 47.00 NI-Hub ATC Price ($/MWh) 62.90 PJM W-Hub ATC Price ($/MWh) 8.50 Henry Hub Gas Price ($/mmBtu) 2008 Open EBITDA (1) Assumptions ~$1,000M + $10/Tonne Carbon Price (3) ~$80M +/- $10/MW-Day Capacity Price ~$750M +/- 500 Btu/KWh ATC Heat Rate ~$560M +/- $1/mmBtu Gas Price (Pre-Tax Impact) 2008 Open EBITDA (1) Sensitivities |
 19 |
 20 Exelon’s Strategic Direction Deliver superior operating performance Support competitive markets Protect the value of our generation Build healthy, self-sustaining delivery companies Take the organization to the next level of performance Advance an environmental strategy that leverages our carbon position Rigorously evaluate new growth opportunities Align our financial management policies with the changing profile of our company + Protect Today’s Value Grow Long-Term Value |
 21 Advancing Exelon’s Low-Carbon Strategy Advocating in favor of climate change legislation that is national, mandatory and economy-wide Taking voluntary action to reduce our greenhouse gas (GHG) emissions 8% by 2008 (1) Continuing to invest in our low-carbon generation portfolio Developing a comprehensive low-carbon energy strategy • Expanding our low-carbon resources • Providing customers with green products and services • Being a model of green operations (1) From 2001 levels |
  22 Potential Nuclear New Build Intend to file Construction and Operating License (COL) for plant in Texas by end of 2008 • Preserves option to participate in Energy Policy Act incentives Texas is attractive market for new nuclear • Growing demand for baseload power, robust market prices • State and local support for new nuclear • Existing Exelon presence in Texas Exelon’s phased approach allows for go/no-go decisions at major funding/commitment milestones Exelon’s conditions for new build remain unchanged: the economics must be right Nuclear new build would capitalize on improving fundamentals, high gas prices,
and Exelon’s core strength in nuclear operations
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  23 Disciplined Financial Management In December 2006, the Exelon Board approved a new “Value Return Policy” The Policy: • Established a base dividend at $1.76/share, growing modestly over time • Returns excess cash and/or balance sheet capacity through share repurchases Consistent with the Policy, we executed a $1.25 billion accelerated share repurchase agreement in September We expect to ask the Exelon Board to consider a normal increase in the dividend for 2008 and to consider expanding the 2007 share repurchase program in the first quarter of 2008 Exelon has an increasingly strong balance sheet that will be deployed both to protect and grow shareholder value |
 24 2007 Exelon Investor Conference Conference Topics 2008 earnings guidance by operating company 2008 sources & uses of cash Operational & regulatory updates Strategic outlook The Waldorf Astoria New York, NY December 19 th Conference Agenda 7:15 AM: Registration & Breakfast 8:00 AM: Conference Program |
 25 Exelon – Value Driven Continued strong financial and operating performance >80% EPS from unregulated generation Largest, lowest-cost nuclear fleet in competitive markets Executing regulatory recovery plan to put ComEd on a path toward appropriate returns and solid credit metrics Managing transition to competitive markets in Pennsylvania Increasingly strong cash flows and balance sheet Implementing value return policy With numerous forces driving the industry, Exelon is uniquely positioned for
continued strong value creation |
 26 |
 27 Appendix |
 28 ’06 Earnings (1) : $1,275M ’07E Earnings (2) : $2,320 - $2,385M ’06 EPS (1) : $1.88 ’07 EPS Guidance (2) : $3.45 - $3.55 Total Debt (3) : $1.8B Credit Rating (4) : BBB+ The Exelon Companies Nuclear, Fossil, Hydro & Renewable Generation Power Marketing ‘06 Operating Earnings (1) : $2.2B ‘07E Operating Earnings (2) : $2.8 - $2.9B ‘07 EPS Guidance (2) :
$4.15 - $4.30 Assets
(12/31/06): $44.3B Total Debt
(12/31/06): $13.0B Credit Rating (4) :
BBB (1) 2006 Adjusted (Non-GAAP) Operating Earnings and Operating EPS. (2) Estimated 2007 Adjusted (Non-GAAP) Operating Earnings and 2007 Operating
Earnings Guidance per Exelon share. (3) As of 12/31/06. (4) Standard & Poor’s senior unsecured debt ratings for Exelon and Generation
and senior secured debt ratings for ComEd and PECO as of 10/31/07. Pennsylvania Utility Illinois Utility ’06 Earnings (1) : $528M $455M ’07E Earnings (2) : $130 - $165M $435 - $470M ’06 EPS (1) : $0.78 $0.67 ’07 EPS Guidance (2) : $0.20 - $0.25 $0.65 - $0.70 Total Debt (3) : $4.6B $4.2B Credit Ratings (4) :
BBB A |
 29 Multi-Regional, Diverse Company Note: Megawatts based on Generation’s ownership as of 10/1/07, using annual mean ratings for nuclear units (excluding Salem) and summer ratings for Salem and the fossil and hydro units; capacity excludes New Boston Unit 1 and State Line PPA. Mid-Atlantic contracts include wind and cogeneration projects. Midwest Capacity Owned: 11,373 MW Contracted: 4,271 MW Total: 15,644 MW ERCOT/South Capacity Owned: 2,222 MW Contracted: 2,917 MW Total: 5,139 MW New England Capacity Owned: 181MW Total Capacity Owned: 24,746 MW Contracted: 7,524 MW Total: 32,270 MW Electricity Customers: 1.6M Gas Customers: 0.5M Electricity Customers: 3.8M Generating
Plants Nuclear Hydro Coal/Oil/Gas Base-load Intermediate Peaker Mid-Atlantic Capacity Owned: 10,970 MW Contracted: 336 MW Total: 11,306 MW |
 30 YTD ‘07 Highlights • Solid financial operating EPS results - Higher generation margins - Favorable weather - Strong nuclear performance • Illinois settlement • Value return plan implementation • ComEd regulatory recovery plan execution Strong Financial Performance Year-to-Date EPS Results $3.26 $2.53 Weather Normalized (2) $3.31 $2.50 Operating Adjusted (non-GAAP) EPS (1) Sep-07 Sep-06 Operating EPS $4.15 - $4.30 (1) Refer to reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.
(2) Excludes $0.03 per share unfavorable impact versus normal in 2006 and $0.05 per share favorable impact versus normal in 2007, based on Exelon models. (3) Operating EPS growth rate through 2007 calculated using midpoint of 2007 Operating
EPS guidance range. YTD 2007 weather-normalized operating earnings are 29% higher than 2006 $3.22 $3.10 $2.78 $2.61 $2.41 $2.24 $1.93 2000 2001 2002 2003 2004 2005 2006 2007E |
    31 Illinois Settlement • Continued ComEd membership in PJM • Competitive procurement for supply • Filed competitive declaration for 100 - 400 kW customers • Statute mandates cost recovery for purchased power • Reduced uncertainty around conditions for ICC approval for strategic transactions such as reorganizations or mergers • Immediate rate relief for customers • Provisions to help stabilize rates • Energy efficiency and demand response programs and renewable portfolio standards • Eliminated the IL Attorney General’s challenges to the 2006 auction • Financial swap at market prices • No generation tax Customer Focused Protects Value of Generation Protects Competitive Markets Provides Strategic Flexibility |
 32 O&M and CapEx Expectations Exelon (1) NM (2) 1-2% 3-4% NM (2) ~15% 2008-2012 CAGR $3,110 $390 $1,000 $870 $730 2008E $2,740 $350 $1,060 $720 $580 2007E Other Nuclear Fuel Capital 2-3% 2-3% 2-3% 2-3% 2008-2012 CAGR $4,240 $650 $1,010 $2,620 2008E $4,090 $620 $1,030 $2,450 2007E Exelon (1) O&M Note: Reflects operating O&M data and excludes Decommissioning Trust Fund
impact. (1) Includes eliminations and other corporate entities.
(2) Due to varying capital investment for the period 2008-2012, the CAGR
is not meaningful. ($ in Millions) |
  33 Industry Is Facing a Capital Investment Challenge Source: Cambridge Energy Research Associates ~$750B Generation for 230+ GWs Transmission Distribution $50B Conservation & Energy Efficiency $50B (excl. Carbon) Environmental Retrofits $300B $350B $150B ~$900B Current Industry Market Cap ($B) Investment required over the next 15 years exceeds the current market capitalization of the entire electric industry CapEx Spend Next 15 Years ($B) |
  34 Ability to Fund Major Investment Cost as % of Market Cap Market Cap (1) ($B) 1.2 247 BP 1.1 278 Royal Dutch Shell 0.6 510 Exxon Mobil 15.0 20 “Average” Investor Owned Utility (excl. Exelon) 10.7 28 3 rd Largest Investor Owned Utility 9.4 32 2 nd Largest Investor Owned Utility 5.5 55 Exelon $3B Power Plant (2) $3B Deep Water Drilling Platform (1) Market Cap as of 10/31/07. (2) Represents approximate equity investment after taking into account government loan
guarantees; includes cost escalation and interest during construction. Large and strong balance sheets will be required for the utility and generation infrastructure investment that must occur |
 35 |
   36 PECO Average Electric Rates (1) System Average Rates based upon Restructuring Settlement Rate Caps on Energy and Capacity increased from original settlement by 1.6% to reflect the roll-in of increased Gross Receipts Tax and $0.02/kWh for Universal Service Fund Charge and Nuclear Decommissioning Cost Adjustment. System Average Rates also adjusted for sales mix based on current sales forecast. Assumes continuation of current Transmission and Distribution Rates. (2) Energy/Capacity Price is an average of the results for residential (10.51¢/kWh) and small commercial customers (10.58¢/kWh) from the second round of PPL Auction held 10/07. Assumes continuation of current Transmission and Distribution Rates.
2011 2008 – 2010 Energy / Capacity Competitive Transition Charge (CTC) Transmission Distribution 11.52¢ (1) Unit Rates (¢/kWh) +18% 13.65¢ (2) CTC terminates at year-end 2010 Energy / Capacity price expected to increase; price will reflect associated full requirements costs Using latest PPL auction for 2010 as a proxy (10.5¢/kWh) results in a system average rate increase of ~18% PECO’s 2011 full requirements price expected to differ from PPL due, in part, to the timing of the procurement and locational differences Rates will vary by customer class and will depend on legislation and approved procurement model Electric Restructuring Settlement Projected Rate Increase Based on PPL Auction Results (IIIustrative) Post Transition 2.63 2.63 0.48 0.48 2.41 6.00 10.54 |
 37 PECO Average Annual Rate Base 2.6 2.7 2.9 3.0 3.1 3.3 2.7 2.0 1.3 1.1 1.1 1.1 1.1 1.2 1.2 0.6 0.6 0.6 0.5 0.5 0.5 0.5 2007E 2008E 2009E 2010E 2011E 2012E Gas CTC Electric Transmission Electric Distribution 6.9 6.3 5.8 5.2 4.9 5.0 ($ in Billions) |
    38 Pennsylvania Snapshot Governor Rendell proposed an Energy Independence Strategy (EIS) in February 2007 Aimed at reducing energy costs, increasing clean energy sources, reducing reliance on foreign fuels and expanding energy production in PA Funded through a systems benefit charge Special legislation session on Energy Policy began September 17th Runs through mid-December Current State of Play Legislators concerned with cost of funding Governor's initiatives, no new taxes Rate freeze and/or generation tax legislation being considered Industry coalition working together to develop a comprehensive package Position of Stakeholders Stakeholder outreach Working with industry coalition Negotiating legislative proposals with Administration and legislative leadership Smart meters and real time pricing Energy efficiency and demand side management programs Procurement Contracts for large industrials Utilities owning generation Rate increase deferral/phase-in Participating directly or through industry associations in legislative hearings and informational meetings Evaluating alternative proposals PECO Actions |
   39 Key Themes of Legislative Proposals Competitive procurement process utilizing auctions, RFPs, spot purchases and bilateral contracts Full and current cost recovery for default service provider (DSP) DSP must offer residential and small commercial customers a rate that changes no more frequently than annually with reconciliation for under or over-recovery Must file a rate phase-in plan for all customers with the option to phase-in
rate increase if class average total rate increases by more than 15% Phase-in plans are to be opt-in for customer, provide utility with full
recovery of carrying costs with return on deferred balance Securitization of deferred balance and carrying charges authorized Utility may propose an early phase-in plan Energy efficiency goal of usage reduction of 2% by 2013 Peak demand reduction goal of 3% by 2012 Utilities may file for cost recovery Full deployment of smart meters within 6-10 years Full recovery for net costs of smart meter deployment through base rates or on full and current basis through automatic recovery mechanism Must submit a time-of-use rate plan with voluntary customer participation by
the end of rate cap period Procurement Smart Meters Rate Phase-in Program Demand Side Response & Energy Efficiency (DSR/EE) |
 40 |
  41 41 ComEd Transmission Case Settlement (1) ($ in millions) FERC Filing 3/1/07 Preliminary Order 6/5/07 Settlement Filing 10/5/07 (1) Total Revenue Requirement (in year 1) (2) $415 $387 $364 Revenue Requirement increase (in year 1) $146 $116 (3) $93 Rate Base (in year 1) $1,826 $1,744 $1,672 (4) Common Equity Ratio 58% 58% 58% (5) Return on Equity (ROE) (6) 12.20% 11.70% + 0.50% RTO adder 12.20% 11.70% + 0.50% RTO adder 11.50% 11.0% + 0.50% RTO adder Return on Rate Base (ROR) 9.87% 9.87% 9.40% (1) Subject to final FERC approval. (2) Included a request for project incentives of $16 million. (3) Rates effective 5/1/07, subject to refund. (4) Excludes pension asset; 6.51% debt return allowed in operating expenses. (5) Equity cap of 58% for 2 years, declining to 55% by 2011. (6) ROE is fixed and not subject to annual updating. RTO = Regional Transmission Organization (Docket Nos. ER07-583-000 & EL07-41-000) Rate settlement establishes reasonable framework for timely recovery of transmission
investment on an annual basis through formula rates
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 42 42 Formula Transmission Rate Annual Update Process (1) Annual filing by May 15 th will update the current year revenue requirement and true-up prior year to actual: Update current year Estimate current year revenue requirement using updated costs based on prior
year actual data per FERC Form 1 plus projected plant additions for the current
calendar year True-up prior year Perform a true-up of the prior year’s rates by comparing prior year actual
data per FERC Form 1 to the estimate used for that year;
over/under-recoveries for the prior year are collected in the current
year Rates take effect on June 1 st Interested parties have 180 days to submit information requests and raise concerns; unresolved concerns go before FERC for resolution (1) Subject to final FERC approval. The combination of annual updating and true-up virtually eliminates regulatory
lag |
  43 ComEd Delivery Service Rate Case Filing $361 (6) Total ($2,049 revenue requirement) $(51) Other adjustments (5) $48 O&M expenses $99 Administrative & General expenses (4) $50 Capital Structure (3) : ROE - 10.75% / Common Equity - 45.11% / ROR - 8.55% $215 (2) Rate Base: $7,071 (1) Requested Revenue Requirement Increase ($ in millions) (1) Based on 2006 test year, including pro forma capital additions through 3Q 2008;
represents a $1,550 million increase from 2006 ICC order. (2) Includes
increased depreciation expense associated with capital additions. (3)
Requested cap structure does not include goodwill; ICC docket 05-0597 allowed 10.045% ROE, 42.86% equity ratio and 8.01% ROR (return on rate base). (4) Primarily includes increases in pension and other post-retirement benefits costs
and effects of a reclassification of rental revenue of $20 million, which is offset in “Other adjustments”. (5) Includes taxes other than income, regulatory expenses, and reductions for other
revenues and load growth. (6) Or approximately $359 million adjusted for
normal weather. Revenue increase needed to recover significant distribution
system investment and represents an important step in
ComEd’sregulatory recovery plan |
 44 ComEd Delivery Service Rate Case Filing – Tentative Schedule Filed – October 17, 2007 Rebuttal Testimony – February 2008 Hearings – May 2008 Administrative Law Judge (ALJ) Order – July 2008 Final Order Expected – September 2008 Note: Dates are based on typical approach to rate cases but the Illinois Commerce Commission (ICC) will set the actual schedule. |
 45 Financial Swap Agreement 3,000 $53.48 January 1, 2013 - May 31, 2013 3,000 $52.37 January 1, 2012 - December 31, 2012 3,000 $51.26 January 1, 2011 - December 31, 2011 3,000 $50.15 June 1, 2010 - December 31, 2010 2,000 $50.15 January 1, 2010 - May 31, 2010 2,000 $49.04 June 1, 2009 - December 31, 2009 1,000 $49.04 January 1, 2009 - May 31, 2009 1,000 $47.93 June 1, 2008 - December 31, 2008 Notional Quantity (MW) Fixed Price ($/MWH) Portion of Term • Financial Swap Agreement between ComEd and Exelon Generation promotes price stability for residential and small business customers • Designed to dovetail with ComEd’s remaining auction contracts for energy,
increasing in volume as the auction contracts expire – Will cover about 60% of the energy that ComEd’s residential and small business
customers use • Includes ATC baseload energy only – Does not include capacity, ancillary services or congestion
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 46 |
    47 Market Price Sensitivities ~$80M +/- 500 Btu/KWh ATC Heat Rate ~$10M +/- $1/mmBtu Gas Price (Pre-Tax Impact) 2008 EBITDA Sensitivities ($80M) ($40M) ($20M) ($5M) - Expense (Pre-Tax Impact)
($335M) ($160M) ($100M) ($60M) - Capital Expenditures 2012 2011 2010 2009 2008 - $50/lb $40M $15M $10M $5M - Expense (Pre-Tax Impact)
$280M $85M $30M $20M - Capital Expenditures 2012 2011 2010 2009 2008 + $50/lb (1) Excludes Salem. Uranium Sensitivity (1) |
 48 Total Portfolio Characteristics 40,900 41,100 23,300 23,100 5,100 126,500 120,000 0 50,000 100,000 150,000 200,000 250,000 2007 2008 Actual Hedges & Open Position ComEd Swap IL Auction PECO Load 189,300 190,700 140,700 138,100 31,600 33,800 18,400 17,400 0 50,000 100,000 150,000 200,000 250,000 2007 2008 Forward / Spot Purchases Fossil & Hydro Nuclear 189,300 190,700 Expected Total Supply (GWh) Expected Total Sales (GWh) The value of our portfolio resides in our nuclear fleet |
     49 Hedging Targets Target Ranges 50% - 70% 70% - 90% 90% - 98% Above the range* Current Position Upper end of range Midpoint of range (1) Percent financially hedged is our estimate of the gross margin that is not at risk
due to a market price drop and assuming normal generation operating conditions. The formula is: gross margin at the 5th percentile / expected gross margin. Power Team employs commodity hedging strategies to optimize Exelon Generation’s earnings: Maintain length for opportunistic sales Use cross commodity option strategies to enhance hedge activities Time hedging around view of market fundamentals Supplement portfolio with load following products Use physical and financial fuel products to manage variability in fossil generation output Financial Hedging Range (1) * Due to ComEd financial swap Flexibility in our targeted financial hedge ranges allows us to be opportunistic while
mitigating downside risk Prompt Year (2008) Second Year (2009) Third Year (2010) |
 50 Financial Swap Agreement 3,000 $53.48 January 1, 2013 - May 31, 2013 3,000 $52.37 January 1, 2012 - December 31, 2012 3,000 $51.26 January 1, 2011 - December 31, 2011 3,000 $50.15 June 1, 2010 - December 31, 2010 2,000 $50.15 January 1, 2010 - May 31, 2010 2,000 $49.04 June 1, 2009 - December 31, 2009 1,000 $49.04 January 1, 2009 - May 31, 2009 1,000 $47.93 June 1, 2008 - December 31, 2008 Notional Quantity (MW) Fixed Price ($/MWH) Portion of Term • Market-based contract for ATC baseload energy only – Does not include capacity, ancillary services or congestion • Preserves competitive markets • Fits with Exelon Generation’s hedging policy and strategy • Small portion of Exelon Generation’s supply |
 51 Reliability Pricing Model Auction 40.80 197.67 111.92 148.80 102.04 191.32 191.32 Rest of Market Eastern MAAC
MAAC + APS 2007/2008 2008/2009 2009/2010 0 1,500 MW N/A N/A N/A N/A MAAC + APS (7) 9,750 - 9,950 MW (3) 9,500 MW 9,550 - 9,850 MW (3) 9,500 MW 9,500 - 9,800 MW (3) 9,500 MW Eastern MAAC 4,750 - 4,950 MW (6) 12,700 MW 6,600 - 6,800 MW 14,500 MW (5) 6,600 - 6,800 MW 16,000 MW (4) Rest of Market Obligation Capacity (2) Obligation Capacity (2) Obligation Capacity (2) 2009 / 2010 2008 / 2009 2007 / 2008 Exelon Generation Participation within PJM Reliability Pricing Model (1) (6) In 09/10, obligation is reduced due to roll-off of part of ComEd auction load
obligation in May 2009. (3) EMAAC obligation consists of load from PECO
and BGS commitments. (7) MAAC = Mid-Atlantic Area Council; APS =
Allegheny Power System. (5) 08/09 Capacity supply decreased due to
roll-off of several purchase power agreements (PPAs). (4) Removing State
Line from the supply in October 2007 reduces this by 515 MW. (2)
All capacity values are in installed capacity terms (summer ratings). (1) All values are approximate and not inclusive of wholesale transactions.
PJM RPM Auction Results ($/MW-day) |
  52 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 5 10 15 20 25 30 35 40 45 0 5 10 15 20 25 30 Carbon Value Midwest • ~90,000 GWhs in Midwest nuclear portfolio • ~55% of time coal on the margin • ~40% of time gas on the margin Mid-Atlantic • ~50,000 GWhs in Mid-Atlantic nuclear portfolio • ~45% of time coal on the margin • ~50% of time gas on the margin Assumes Open Position (1) Carbon Credit ($/Tonne) (1) Carbon sensitivity excludes ComEd SWAP and upside of Kincaid/Elwood due to contract
expiration in 2012. Assumes below $45/tonne carbon cost, no carbon reduction technology (e.g., sequestration) is economical. (2) As of 10/31/07. (3) The EIA Carbon Stabilization Case (Case 4) dated March 2006, EIA report number SR/OIAF/2006-1. (4) Low Carbon Economy Act initial “Technology Accelerator Payment” (TAP) price in 2012. Allowance price increases at 5% above the rate of inflation thereafter. Carbon Value Climate change legislation is expected to drive substantial gross margin expansion
at Exelon Generation Europe Carbon Trading 2012: $35.50/tonne (2) Bingaman-Specter (4) 2012: $12/tonne EIA Carbon Case (3) 2010: $31/tonne Lieberman-Warner Possible $20 to $40/tonne |
 53 Required Break-Even Cost by Technology (Illustrative) 0 20 40 60 80 100 Nuclear Coal Integrated Gasification Combined Cycle Combined Cycle Gas Turbine In 2008$ CO2 @ $10/tonne Fixed / Variable Cost Recovery Note: See following page for assumptions. Break-even price determined by using
mid-point of capital cost. (1) 2008 ERCOT Forward Price = $64.00/MWh ATC
as of 10/31/07. 2008 ERCOT Forward Price (1) |
 54 Required Break-Even Cost by Technology – Illustrative Assumptions Combined Cycle Gas Turbine (CCGT) Integrated Gasification Combined Cycle (IGCC) Coal (Pulverized) Nuclear (Dual-Unit) Assumption Construction time (years) Permitting time (years) CO2 - $/tonne 2008 Market fuel cost (held flat for fossil fuels) Fuel type Range of all-in capital cost ($/kw) (overnight, without interest during construction) Capacity net MWe 10 10 10 N/A $7.68/ MMBtu $2.22/ MMBtu $2.22/MMBtu $10.00/MWh 2 3 2 3 2 4 3 5 Gas Coal Coal Nuclear 800 – 1,200 2,800 – 3,000 2,100 – 2,400 2,800 – 3,400 500 500 500 3,000 Global Assumptions: In 2008$; 40-year life assumed; 9-12% after-tax weighted avg. cost of
capital; 32% effective tax rate; ~1%-3% cost escalation. Fuel assumptions are PRB (coal) and Houston Ship Channel (gas).
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 55 Exelon Nuclear Fleet Overview 2011 42.6% Exelon, 56.4 % PSEG 2016, 2020 969 (1) W PWR 2 Salem, NJ Life of plant capacity 100% AmerGen 2014; renewal to be filed 2008 837 B&W PWR 1 TMI-1, PA Dry cask 100% AmerGen 2009; renewal filed 2005 625 GE BWR 1 Oyster Creek, NJ Dry cask 50% Exelon, 50% PSEG Renewed: 2033, 2034 1135 (1) GE BWR 2 Peach Bottom, PA Dry cask 75% Exelon, 25% Mid- American Holdings Renewed: 2032 1303 (1) GE BWR 2 Quad Cities, IL Dry cask 100% Renewed: 2029, 2031 871, 871 GE BWR 2 Dresden, IL 2012 100% 2022, 2023 1138, 1150 GE BWR 2 LaSalle, IL Dry cask in process 100% 2024, 2029 1151, 1151 GE BWR 2 Limerick, PA Re-rack completed 2011 2013 Spent Fuel Storage/ Date to lose full core discharge capacity GE W W Vendor BWR PWR PWR Type 1 2 2 Units 100% AmerGen 2026 1048 Clinton, IL 100% 2024, 2026 1183, 1153 Byron, IL 100% 2026, 2027 1194, 1166 Braidwood, IL Ownership License Expiration / Status Net Annual Mean Rating MW Plant, Location Fleet also includes 4 shutdown units: Peach Bottom 1, Dresden 1, Zion 1 &
2. (1) Capacity based on ownership interest. |
  56 Energy Policy Act – Nuclear Incentives $18 per MWh, 8 year PTC for first 6,000 MWe of new capacity Cap of $125M per 1,000 MWe of capacity per year Protects against a decrease in market prices and revenues earned Benefit will be allocated/ prorated among those who: • File COL by year-end 2008 • Begin construction (first safety-related concrete) by 1/1/2014 • Place unit into service by 1/1/2021 Production Tax Credit (PTC) Results in ability to obtain non-recourse project financing Up to 80% of the project cost, repayment within 30 years or 90% of the project life Timing of application subject to DOE solicitations for projects Loan guarantee volume dependent upon congressional appropriations action Government Loan Guarantee “Insurance” protecting against regulatory delays in commissioning a completed plant • First two reactors would receive immediate “standby interest coverage” including replacement power up to $500M • The next four reactors would be covered up to $250M after six months of delay Regulatory Delay “Backstop” Energy Policy Act provides financial incentives and reduced risk by way of production tax credits and loan guarantees |
 57 Announced Nuclear Projects Announced intent Greenfield San Joaquin Valley CA EPR 1 Fresno Nuclear Energy Announced intent Greenfield Bruneau ID EPR 1 Alternative Energy Hldings Letter of intent Operating Turkey Pt FL TBD TBD FPL Letter of intent Operating Susquehanna PA EPR 1 PPL Letter of intent Operating Fermi MI TBD 1 DTE Energy Letter of intent Greenfield Victoria or Matagorda TX TBD TBD Exelon Letter of intent Operating Comanche Peak TX APWR 2 TXU Letter of intent Operating Callaway MO EPR 1 Unistar/Ameren Letter of intent Operating Nine Mile Pt NY EPR 1 Unistar COL submitted Sept 2007 Operating South Texas Project TX ABWR 2 NRG Energy Letter of intent Greenfield Amarillo TX EPR 2 Amarillo Power COL Jan 2008 Operating Harris NC AP1000 2 Progress COL 2008 Operating Vogtle GA AP1000 2 Southern COL May 2008 Operating River Bend LA ESBWR 1 Entergy Letter of intent Characterized Lee SC AP1000 2 Duke COL July 2008 Greenfield Levy Co. FL AP1000 2 Progress Letter of intent Operating Summer SC AP1000 2 South Carolina E&G ESP approved; COL February 2008 Operating Grand Gulf MS ESBWR 1 Entergy/NuStart COL submitted Oct 2007. Reference plant for AP1000 Characterized Bellefonte AL AP1000 2 TVA/NuStart Reference plant for ESBWR COL application; planned for 2007 Operating North Anna VA ESBWR 1 Dominion Partial COL submitted; remainder expected in 2007 Operating Calvert Cliffs MD EPR 1 Unistar Status Type of site Site Technology Units Applicant 21 projects totaling ~39,000 MWs have been announced |
 58 Advanced Nuclear Designs – U.S. Market Luminant (formerly TXU) Will apply for design certification in 2008 1700 MW Mitsubishi APWR (Advanced PWR) NRG Evolutionary improvement from current BWR. Design certification in 1997. In operation in Japan since 1996. 1350 MW GE-Hitachi ABWR (Advanced BWR) UniStar PPL Ameren Alternate Energy Holdings Design certification to be filed 1Q 2008. AREVA in UniStar joint venture with Constellation to deploy EPR in US. Under construction in Finland, France 1600 MW AREVA EPR (Evolutionary PWR) TVA/NuStart SCE&G Progress Duke Southern PWR, passive safety features, Design certification received December 2005 1150 MW Westinghouse AP1000 (Advanced Passive 1000) Dominion Entergy/NuStart at Grand Gulf Entergy at River Bend Passive safety features, simplified from ABWR design. NRC design certification expected 2010 1500 MW GE-Hitachi ESBWR (Economic Simplified Boiling Water Reactor) Selected in US by: Status Capacity Vendor Reactor Sources: World Nuclear Association; Nuclear Fuel Cycle Monitor, September 17, 2007. |
 59 0 1 2 3 4 5 6 7 8 9 10 Building a new nuclear plant is not a one-step process or decision: It is a sequence of 3 successive decisions Years (estimates) 1 2 3 First Decision: File an application for a COL Second Decision: Procure major long-lead procurement components and commodities Third Decision: Proceed with construction Source: Exelon estimates. Roadmap to Nuclear Commercial Operation |
 60 0 20 40 60 80 100 120 140 160 Uranium Price Volatility 0 20 40 60 80 100 120 140 160 Spring 2003 McArthur River flood December 2003 GNSS/Tenex termination; ConverDyn UF6 release and shutdown Early 2004 ERA / Ranger water problems Early 2006 First Cigar Lake flood; Cyclone Monica halts ERA / Ranger operations for approximately two weeks October 2006 Second Cigar Lake flood March 2007 ERA / Ranger flooding (cyclone George) Long-term Uranium Price Trend Seven-Month Uranium Price Trend Long-term equilibrium price expected to be $40-$60/lb
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 61 Current Market Prices 1. 2004, 2005 and 2006 are actual settled prices. 2. Real Time LMP (Locational Marginal Price). 3. Next day over-the-counter market. 4. Average NYMEX settled prices. 5. 2007 information is a combination of actual prices through 10/31/07 and market prices
for the balance of the year. 6. 2008 and 2009 are forward market prices as of 10/31/07. PRICES (as of October 31, 2007) Units 2004 2005 2006 1 2007 5 2008 6 2009 6 PJM West-Hub ATC ($/MWh) 42.35 60.92 51.07 2 59.56 65.94 68.01 PJM NI-Hub ATC ($/MWh) 30.15 46.39 41.42 45.77 50.17 51.55 NEPOOL MASS Hub ATC ($/MWh) 52.13 76.65 59.68 65.61 77.03 78.98 ERCOT North On-Peak ($/MWh) 49.53 76.90 60.87 3 60.08 74.76 78.95 Henry Hub Natural Gas ($/MMBTU) 5.85 8.85 4 6.74 4 7.07 8.48 8.69 WTI Crude Oil ($/bbl) 41.48 4 56.62 4 66.38 4 69.67 88.79 83.19 PRB 8800 ($/Ton) 5.97 8.06 13.04 9.70 11.50 12.30 NAPP 3.0 ($/Ton) 60.25 52.42 43.87 47.97 54.50 53.50 ATC HEAT RATES (as of October 31, 2007) PJM West-Hub / Tetco M3 (MMBTU/MWh) 6.40 6.30 6.98 7.56 7.01 7.04 PJM NI-Hub / Chicago City Gate (MMBTU/MWh) 5.52 5.52 6.32 6.55 5.94 5.91 ERCOT North / Houston Ship Channel (MMBTU/MWh) 7.53 8.21 8.28 7.73 7.83 7.92 4 3 2 2 2 1 1 2 2 3 2 2 2 |
 62 62 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 8 8.1 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 55 60 65 70 75 80 85 90 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 7.4 7.6 7.8 8 8.2 8.4 8.6 8.8 9 9.2 9.4 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 Market Price Snapshot As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are
daily. Forward NYMEX Natural Gas PJM-West and NI-Hub On-Peak Forward Prices PJM-West On-Peak Implied Heat Rate NI-Hub On-Peak Implied Heat Rate 8.84 9.04 9.24 9.44 9.64 9.84 10.04 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 2008 2009 2009 2008 2008 PJM-West 2009 PJM-West 2009 Ni-Hub 2008 Ni-Hub 2008 2009 |
 63 63 25 27 29 31 33 35 37 39 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 40 42 44 46 48 50 52 54 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 40 42 44 46 48 50 52 54 56 58 60 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 50 52 54 56 58 60 62 64 66 68 70 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 Market Price Snapshot As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are
daily. PJM-West ATC Forward Prices 2008 2009 PJM-West Wrap Forward Prices 2008 2009 NI-Hub ATC Forward Prices NI-Hub Wrap Forward Prices 2009 2008 2009 2008 |
 64 64 49 51 53 55 57 59 61 63 65 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 7.7 7.8 7.9 8 8.1 8.2 8.3 8.4 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 58 60 62 64 66 68 70 72 74 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 7 7.5 8 8.5 9 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 Market Price Snapshot 2008 2009 2009 2008 2008 2009 As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are
daily. 2008 2009 Houston Ship Channel Natural Gas Forward Prices ERCOT North ATC Forward Prices ERCOT North ATC v. Houston Ship Channel Implied Heat Rate ERCOT North Wrap Forward Prices |
 65 65 65 67 69 71 73 75 77 79 81 83 85 1/2/07 2/2/07 3/2/07 4/2/07 5/2/07 6/2/07 7/2/07 8/2/07 9/2/07 10/2/07 Market Price Snapshot ERCOT North On-Peak Forward Prices 2008 2009 As of October 31, 2007. Source: OTC quotes and electronic trading system. Quotes are
daily. |
 66 Exelon – Climate Change |
 67 Recognized Environmental Leadership Named to the 2006/2007 and 2007/2008 Dow Jones Sustainability North America Index Named to Climate Disclosure Leadership Index of the Carbon Disclosure Project in 2005, 2006 and 2007 Signatory to the Global Roundtable on Climate Change and the Ceres/Investor Network on Climate Risk statements Member of the United States Climate Action Partnership (USCAP) Corporate headquarters awarded Leadership in Energy and Environmental Design (LEED ® ) Platinum Commercial Interiors certification by the U.S. Green Building Council |
 68 Exelon’s Climate Actions Achieved SF6 leak rate of under 10% for 2006 Provides customer-based energy-efficiency programs (compact fluorescent light bulbs, demand response programs) – will ramp up to one of the country’s leading programs in four years ComEd is the largest private user of biodiesel in Illinois thereby helping to create a healthy biodiesel market First utility in PA to file to meet Tier 1 requirements under Alternative Energy Portfolio Standards (AEPS) Achieved SF6 leak rate of under 10% for 2006 Supporting implementation of smart meters system-wide and time-of-use programs Nation’s largest low-carbon generation Retired older, inefficient plant Invested in landfill gas power generation expansion Committed to going beyond world-class nuclear performance and compliance with
regulations, Exelon is taking voluntary action to address climate
change Largest marketer of wind power east of the Mississippi River Signed 20-year deal to purchase output from largest solar photovoltaic installation in PJM region |
 69 Exelon and Federal Climate Change Legislation Actively involved in the climate debate in Washington, D.C. Lobbying in favor of enacting legislation that is national, mandatory and economy-wide Favors a cap-and-trade system over a carbon tax Believes that any allocation scheme should include allowances for distribution companies to help offset the cost of carbon for the end-user To limit near-term economic impacts, supports a “safety valve” for cost of carbon that needs to increase over time |
 70 Reduction Goals 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 Historical U.S. emissions (EPA, 1990-2005) Business-as-usual projection (AEO2007) Sanders-Boxer / Waxman Kerry-Snowe McCain-Lieberman Bingaman-Specter assuming "safety valve" not hit Lieberman-Warner draft principles Olver-Gilchrest Bingaman-Specter assumes multiple low-carbon policies, including: • Car & light truck fuel economy of 41 mpg by 2027 • Federal RPS of 15% by 2020 • Optimistic assumptions about new technologies coming online Under these policies, the safety valve is not triggered. Without these policies the safety valve is expected to be reached in the early years and the target will be exceeded. The program ends in 2030 unless the President sets additional long-term targets. Comparison of Economy-wide Cap-and-Trade Emissions Targets Includes Legislation Introduced in the 110th Congress as of September 2007
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 71 CO2 Reductions Demand Multiple Generation Technologies Source: Electric Power Research Institute EIA Base Case 2007 The technical potential exists for the U.S. electricity sector to significantly reduce CO2 emissions over the coming decades No one technology will be a silver bullet – a portfolio of technologies will be needed Much of the needed technology is not available yet – substantial R&D and demonstration are required To stabilize emissions at 1990 levels, multiple technologies and intensive R&D will be required 0 500 1000 1500 2000 2500 3000 3500 1990 1995 2000 2005 2010 2015 2020 2025 2030 Advanced Coal Generation Distributed Energy Resources Plug-In Hybrid Electric Vehicles Carbon Capture & Storage Nuclear Generation Renewables Efficiency Technology |
 72 Key Climate Bills Several bills and white papers and drafts are gaining support in Washington: • Bingaman-Specter (S. 1766, the Low Carbon Economy Act of 2007) Economy-wide: All major GHG producing sectors o Point of regulation: Oil and natural gas refineries and coal-fired generators
Increasing auction of allowances o Allowance allocations include: 9% to states, 53% to industry declining 2% per year
starting in 2017, 5% set aside for agricultural o Safety Valve: Price of allowances capped at $12/tonne of CO2 (“technology
accelerator payment”) starting in 2012 and increasing 5% per year
above inflation rate • Lieberman-Warner (S. 2191, America’s Climate Security Act of 2007) Major vehicle for action in the U.S. Senate Environment and Public Works
Committee Economy-wide: All major GHG producing sectors o Point of regulation: Electric power sector- large generators; Industrial sector: Large facilities emitting more than 10,000 tonnes per year o Increasing auction of allowances o Allowance allocations include: 4% to states, 19% to power plants (transitions to zero in 2034), 20% to industry, 10% to electricity load-serving entities o Creates Carbon Market Efficiency Board to allow for borrowing of future year allowances with payback; limited authority to oversee market • Dingell-Boucher White Paper Reduce emissions by 60% to 80% by 2050 Best achieved by a cap-and-trade system |
 73 Key Assumptions, Projected 2007 Credit Measures & GAAP Reconciliation |
 74 Projected 2007 Key Credit Measures 62% – 52% 52% 53% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 49% 12% – 20% 18% 17% FFO / Debt 2.5x – 3.5x A 4.4x 4.4x FFO / Interest PECO: 52% – 42% 58% 61% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 43% 25% – 40% 12% 10% FFO / Debt 3.5x – 5.5x BBB 3.0x 3.0x FFO / Interest ComEd: 52% – 42% 40% 58% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 38% 25% – 40% 79% 41% FFO / Debt 3.5x – 5.5x BBB+ 12.4x 6.5x FFO / Interest Generation: 63% 28% 5.6x Without PPA & Pension / OPEB 55% – 45% 70% Rating Agency Debt Ratio Adjusted Book Debt Ratio: 54% 20% – 30% 22% FFO / Debt 3.2x – 4.5x BBB 4.6x FFO / Interest Exelon Cons: “BBB” Target Range (3) S&P Credit Ratings (2) With PPA & Pension / OPEB (1) Notes: Projected credit measures reflect impact of Illinois electric rates and policy
settlement. Exelon, ComEd and PECO metrics exclude securitization debt. See following slide for FFO (Funds from Operations)/Interest, FFO/Debt and Adjusted Book Debt Ratio reconciliations to GAAP. (1) Reflects S&P updated guidelines, which include imputed debt and interest related to
purchased power agreements (PPA), unfunded pension and other postretirement benefits (OPEB) obligations, and capital adequacy for energy trading. Debt is imputed for
estimated pension and OPEB obligations by operating company. (2) Current senior unsecured ratings for Exelon and Generation and senior secured ratings
for ComEd and PECO as of 10/31/07. (3) Based on S&P Business Profiles: 7 for Exelon, 8 for Generation and ComEd, and 4 for
PECO. Exelon’s balance sheet is strong |
 75 FFO Calculation and Ratios (updated) FFO Calculation = FFO - PECO Transition Bond Principal Paydown + Gain on Sale, Extraordinary Items and Other Non-Cash Items (3) + Change in Deferred Taxes + Depreciation, amortization (including nucl fuel amortization), AFUDC/Cap. Interest Add back non-cash items: Net Income = Adjusted Interest + 7% of Present Value (PV) of Operating Leases + Interest on imputed debt related to PV of Purchased Power Agreements (PPA), unfunded Pension and Other Postretirement Benefits (OPEB) obligations, and Capital Adequacy for Energy Trading (2) , as applicable - PECO Transition Bond Interest Expense Net Interest Expense (Before AFUDC & Cap. Interest) Adjusted Interest FFO+ Adjusted Interest FFO Interest Coverage + Capital Adequacy for Energy Trading (2) FFO = Adjusted Debt + PV of Operating Leases + 100% of PV of Purchased Power Agreements (2) + Unfunded Pension and OPEB obligations (2) + A/R Financing Add off-balance sheet debt equivalents: - PECO Transition Bond Principal Balance + STD + LTD Debt: Adjusted Debt (1) FFO Debt Coverage = Total Rating Agency Capitalization + Off-balance sheet debt equivalents (2) - Goodwill Total Adjusted Capitalization = Rating Agency Debt + ComEd Transition Bond Principal Balance + Off-balance sheet debt equivalents (2) Adjusted Book Debt Rating Agency Capitalization Rating Agency Debt = Total Adjusted Capitalization + Adjusted Book Debt + Preferred Securities of Subsidiaries + Total Shareholders' Equity Capitalization: = Adjusted Book Debt - Transition Bond Principal Balance + STD + LTD Debt: Total Adjusted Capitalization Adjusted Book Debt Debt to Total Cap Note: Updated to reflect revised S&P guidelines and company forecast. FFO and
Debt related to non-recourse debt are excluded from the calculations. (1)
Use current year-end adjusted debt balance. (2) Metrics are calculated in
presentation unadjusted and adjusted for debt equivalents and related interest for PPAs, unfunded Pension and OPEB obligations, and Capital Adequacy for Energy Trading. (3) Reflects depreciation adjustment for PPAs and decommissioning interest income and
contributions. |
 76 GAAP EPS Reconciliation 2000-2002 2000 GAAP Reported EPS $1.44 Change in common shares (0.53) Extraordinary items (0.04) Cumulative effect of accounting change -- Unicom pre-merger results 0.79 Merger-related costs 0.34 Pro forma merger accounting adjustments (0.07) 2000 Adjusted (non-GAAP) Operating EPS $1.93 2001 GAAP Reported EPS $2.21 Cumulative effect of adopting SFAS No. 133 (0.02) Employee severance costs 0.05 Litigation reserves 0.01 Net loss on investments 0.01 CTC prepayment (0.01) Wholesale rate settlement (0.01) Settlement of transition bond swap -- 2001 Adjusted (non-GAAP) Operating EPS $2.24 2002 GAAP Reported EPS $2.22 Cumulative effect of adopting SFAS No. 141 and No. 142 0.35 Gain on sale of investment in AT&T Wireless (0.18) Employee severance costs 0.02 2002 Adjusted (non-GAAP) Operating EPS $2.41 |
 77 2004 GAAP Reported EPS $2.78 Charges associated with debt repurchases 0.12 Investments in synthetic fuel-producing facilities (0.10) Employee severance costs 0.07 Cumulative effect of adopting FIN 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 Charges related to the now terminated merger with PSEG 0.01 2004 Adjusted (non-GAAP) Operating EPS $2.78 2003 GAAP Reported EPS $1.38 Boston Generating impairment 0.87 Charges associated with investment in Sithe Energies, Inc. 0.27 Employee severance costs 0.24 Cumulative effect of adopting SFAS No. 143 (0.17) Property tax accrual reductions (0.07) Enterprises’ Services goodwill impairment 0.03 Enterprises’ impairments due to anticipated sale 0.03 March 3 ComEd Settlement Agreement 0.03 2003 Adjusted (non-GAAP) Operating EPS $2.61 GAAP EPS Reconciliation 2003-2005 2005 GAAP Reported EPS $1.36 Investments in synthetic fuel-producing facilities (0.10) Charges related to the now terminated merger with PSEG 0.03 Impairment of ComEd’s goodwill 1.78 2005 financial impact of Generation’s investment in Sithe (0.03) Cumulative effect of adopting FIN 47 2005 Adjusted (non-GAAP) Operating EPS 0.06 $3.10 |
 78 GAAP Earnings Reconciliation Year Ended December 31, 2006 776 - - 776 - Impairment of ComEd’s goodwill (52) - - (52) - Recovery of debt costs at ComEd (89) - - - (89) Nuclear decommissioning obligation reduction (95) - - (95) - Recovery of severance costs at ComEd $(83) - 1 36 24 - $(144) Other $2,175 1 18 58 24 (58) $1,592 Exelon $455 - 4 10 - - $441 PECO $528 - 4 4 - 3 $(112) ComEd ExGen (in millions) 9 Severance charges 8 Charges related to now terminated merger with PSEG $1,275 2006 Adjusted (non-GAAP) Operating Earnings (Loss) 1 Impairment of Generation’s investments in TEG and TEP - Investments in synthetic fuel-producing facilities (61) Mark-to-market adjustments from economic hedging activities $1,407 2006 GAAP Reported Earnings (Loss) Note: Amounts may not add due to rounding. |
 79 GAAP EPS Reconciliation Year Ended December 31, 2006 $3.22 (0.11) 0.67 $0.78 $1.88 2006 Adjusted (non-GAAP) Operating EPS $2.35 (0.21) 0.65 (0.17) $2.08 2006 GAAP Reported EPS - - - - - 0.05 0.04 - Other (1) (0.14) 1.15 (0.08) - 0.01 0.01 - - ComEd (1) - - - (0.13) 0.01 0.01 - (0.09) ExGen (1) - - - - 0.01 0.01 - - PECO (1) Exelon 1.15 Impairment of ComEd’s goodwill (0.08) Recovery of debt costs at ComEd 0.03 Severance charges (0.13) Nuclear decommissioning obligation reduction (0.14) Recovery of severance costs at ComEd 0.09 Charges related to now terminated merger with PSEG 0.04 Investments in synthetic fuel-producing facilities (0.09) Mark-to-market adjustments from economic hedging activities Note: Amounts may not add due to rounding. (1) Amounts shown per Exelon share and represent contributions to Exelon's EPS.
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 80 GAAP EPS Reconciliation Nine Months Ended September 30, 2006 $2.50 Q3 2006 YTD Adjusted (non-GAAP) Operating EPS (0.08) Recovery of debt costs at ComEd 1.15 Impairment of ComEd's goodwill 0.02 Severance charges (0.13) Nuclear decommissioning obligation reduction 0.09 Charges related to now terminated merger with PSEG 0.08 Investments in synthetic fuel-producing facilities (0.11) Mark-to-market adjustments from economic hedging activities $1.48 Q3 2006 YTD GAAP Reported EPS |
 81 GAAP EPS Reconciliation Nine Months Ended September 30, 2007 $3.31 Q3 2007 YTD Adjusted (non-GAAP) Operating EPS (0.01) Sale of Generation's investments in TEG and TEP 0.14 2007 Illinois electric rate settlement (0.01) Settlement of a tax matter at Generation related to Sithe (0.03) Nuclear decommissioning obligation reduction (0.10) Investments in synthetic fuel-producing facilities 0.12 Mark-to-market adjustments from economic hedging activities $3.20 Q3 2007 YTD GAAP Reported EPS |
 82 2007/2008 Earnings Outlook Exelon’s outlook for 2007/2008 adjusted (non-GAAP) operating earnings excludes the earnings impacts of the following: • mark-to-market adjustments from economic hedging activities • significant impairments of intangible assets, including goodwill • significant changes in decommissioning obligation estimates • investments in synthetic fuel-producing facilities • costs associated with the Illinois electric rate settlement, including ComEd’s previously announced customer rate relief programs • gains or losses on the State Line Energy, L.L.C. and Tenaska Georgia Partners, LP transactions (2007 only) • other unusual items which the Company is unable to forecast • significant future changes to GAAP Both our operating earnings and GAAP earnings guidance are based on the assumption of normal weather |
 83 Net income (loss) +/- Cumulative effect of changes in accounting principle +/- Discontinued operations +/- Minority interest + Income taxes Income (loss) from continuing operations before income taxes and minority interest + Interest expense + Interest expense to affiliates - Interest income from affiliates + Depreciation and amortization Earnings before interest, taxes, depreciation and amortization (EBITDA) Reconciliation of Net Income to EBITDA |
 84 Exelon Investor Relations Contacts Inquiries concerning this presentation should be directed to: Exelon Investor Relations 10 South Dearborn Street Chicago, Illinois 60603 312-394-2345 312-394-4082 (Fax) For copies of other presentations, annual/quarterly reports, or to be added to our email distribution list please contact: Felicia McGowan, Executive Admin Coordinator 312-394-4069 Felicia.McGowan@ExelonCorp.com Investor Relations Contacts: Chaka Patterson, Vice President 312-394-7234 Chaka.Patterson@ExelonCorp.com JaCee Burnes, Director 312-394-2948 JaCee.Burnes@ExelonCorp.com Marybeth Flater, Manager 312-394-8354 Marybeth.Flater@ExelonCorp.com Len Epelbaum, Principal Analyst 312-394-7356 Len.Epelbaum@ExelonCorp.com |