licenses, new sites, waste disposal, decommissioning, fuel source + supply

from exelon’s 10-k








Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for Peach Bottom Units 2 and 3, Dresden Units 2 and 3, and Quad Cities Units 1 and 2. The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:




   Unit    In-Service
Date (e)
   Current License

Braidwood (a)

   1    1988    2026
     2    1988    2027

Byron (a)

   1    1985    2024
     2    1987    2026

Clinton (c)

   1    1987    2026

Dresden (a, d)

   2    1970    2029
     3    1971    2031

LaSalle (a)

   1    1984    2022
     2    1984    2023

Limerick (b)

   1    1986    2024
     2    1990    2029

Oyster Creek (c)

   1    1969    2009

Peach Bottom (b, d)

   2    1974    2033
     3    1974    2034

Quad Cities (a, d)

   1    1973    2032
     2    1973    2032

Salem (b)

   1    1977    2016
     2    1981    2020

Three Mile Island (c)

   1    1974    2014


(a) Stations previously owned by ComEd.
(b) Stations previously owned by PECO.
(c) Stations previously owned by AmerGen.
(d) NRC license renewals have been received for these units.
(e) Denotes year in which nuclear unit began commercial operations.


In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. In July 2005, Generation applied for license renewal for Oyster Creek on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. The application was challenged by various citizen groups and the New Jersey Department of Environmental Protection (NJDEP). The contentions raised by these groups were reviewed and rejected by NRC’s Atomic Safety Licensing Board (ASLB). In January 2008, the citizens group appealed the rejection of its contention to the NRC Commissioners. If the NRC Commissioners reject the appeal, the citizens group can further appeal to the Federal courts. The NJDEP appealed to the Third Circuit Court of Appeals one of its rejected contentions asserting that the NRC must consider terrorism risks as part of the re-licensing proceeding. This contention had previously been rejected by the ASLB and the NRC Commissioners. Further, in January 2008, AmerGen received a letter from the NJDEP concluding that Oyster Creek’s continued operation is consistent with New Jersey’s Coastal Management Program, and approving Oyster Creek’s coastal land use plans for the next 20 years. This consistency determination is a necessary element for license renewal. With the NJDEP consistency determination and the rejection of the sole remaining contention by the ASLB, Generation is currently awaiting the Commission’s decision on appeal and completion of the NRC staff’s consideration of the license renewal for Oyster Creek. The NRC’s approval is expected in the first quarter of 2009.


On January 8, 2008, AmerGen submitted an application to the NRC to extend the operating license of TMI Unit 1 for an additional 20 years from the expiration of its current license to April 2034.




The NRC is expected to spend up to 30 months to review the application before making a decision. To date there have been no legal challenges to the application and the time for filing objections has expired. Generation expects approval of the application to be granted by the NRC.


Generation expects to apply for and obtain approval of license renewals for the remaining facilities. The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the original license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual and assumed renewal of operating licenses for all of Generation’s operating nuclear generating stations.


Generation is a member of NuStart Energy Development, LLC (NuStart), a consortium of ten companies that was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process. As of December 31, 2008, Generation’s investment in NuStart was $2 million.


New Site Development. Generation pursues growth opportunities that are consistent with its disciplined approach to investing to maximize shareholder value, taking earnings, cash flow and financial risk into account. Generation currently is involved in development activities that would allow for the possible construction of a new nuclear plant in Texas. These development activities preserve for Exelon and Generation the option to develop a new nuclear plant in Texas without immediately committing to the full project. In order to continue preserving and assessing this option, Exelon and Generation have approved expenditures on the project of up to $100 million, which includes fees and costs related to the application process for a combined Construction and Operating License (COL), reservation payments and other costs for long-lead components of the project, and other site evaluation and development costs. Amounts spent on the project through December 31, 2008 have been expensed and total approximately $76 million. The development phase of the project is expected to extend into 2009, with approval of funding beyond the $100 million commitment subject to management review and Exelon board approval. Generation has not made a decision to build a new nuclear plant at this time.


On December 7, 2007, Generation reached an agreement with the City of San Antonio acting by and through the City Public Service Board, a Texas municipal utility known as CPS Energy (CPS), under which CPS agreed to fund a portion of Generation’s exploratory costs associated with the possible new nuclear power plant in southeast Texas and related costs for long-lead components. In exchange for its funding commitment, CPS received an option to acquire up to a 40% ownership interest in the new plant and its energy output. If CPS exercises its option, it will be obligated to fund its proportionate share of all project costs and liabilities. The decision whether to build the new nuclear plant will continue to reside solely with Exelon and Generation.


On September 2, 2008, Generation submitted its COL application to the NRC seeking authorization to build and operate a new dual unit nuclear generating facility in Victoria County in southeast Texas. Allowing the NRC 35 months to perform a technical review and 12 months for public hearings, the COL could be issued in 2012. In addition, Generation filed Part I and Part II of a loan guarantee application with the U.S. Department of Energy (DOE) for these potential new units on September 26, 2008 and December 18, 2008, respectively. In November 2008, Generation announced that it was considering alternative technologies to the Economic Simplified Boiling Water Reactor (ESBWR) technology initially selected for the project. Generation has since determined to select a technology other than the ESBWR technology and continues to evaluate alternative technologies. Generation expects to file an amendment to its Part II loan guarantee application in March 2009 to address technology choice.




Among the various conditions that must be resolved before any formal decision to build is made by Generation are the successful granting of the COL by the NRC; significant progress to resolve questions around the short-term interim and long-term permanent storage, as well as potential future recycling, of spent nuclear fuel (SNF); broad public acceptance of a new nuclear plant; and assurances that a new plant can be financially successful, which would entail economic analysis that would incorporate assessing construction and financing costs, including the availability of sufficient financing, production and other potential tax credits, and other key economic factors. However, the decision to build the new nuclear plant depends, in large part, upon financial support under the DOE loan guarantee program. At this time, there is considerable uncertainty about the likelihood of DOE financial support for the project due to the limited appropriations available to DOE for this purpose and the number of projects competing for those limited resources.


Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities in on-site storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation is developing dry cask storage facilities, as necessary, to support operations.


As of December 31, 2008, Generation had approximately 50,600 SNF assemblies (12,200 tons) stored on site in SNF pools or dry cask storage. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites through the license renewal period, and through decommissioning, until the DOE completes removing SNF from the sites. The following table describes the current status of Generation’s SNF storage facilities.




   Date for loss of full core reserve (a)








   Dry cask storage in operation




   Dry cask storage in operation

Oyster Creek

   Dry cask storage in operation

Peach Bottom

   Dry cask storage in operation

Quad Cities

   Dry cask storage in operation



Three Mile Island

   Life of plant storage capable in SNF pool


(a) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to receive a full complement of fuel from the reactor core. Dry cask storage will be in operation at those sites prior to the closing of their on-site storage pools.


For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 13 of the Combined Notes to Consolidated Financial Statements.


As a by-product of their operations, nuclear generating units produce low-level radioactive waste (LLRW). LLRW is accumulated at each generating station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into an agreement, although neither state currently has an operational site and none is currently expected to




be operational until after 2011. Pennsylvania, which had agreed to be the host site for LLRW disposal facilities for generators located in Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for a permanent disposal site.


Generation has on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW to disposal facilities in South Carolina, which at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey and Connecticut which include Oyster Creek and Salem, and Utah. With a limited number of available LLRW disposal facilities, Generation continues to anticipate difficulties in shipping of LLRW off of its sites and continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize cost impacts.


Nuclear Insurance. Generation is subject to liability, property damage and other risks associated with a major accidental outage at any of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other protection provisions. See “Nuclear Insurance” within Note 18 of the Combined Notes to Consolidated Financial Statements for details.


For information regarding property insurance, see ITEM 2. Properties—Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s and Generation’s financial condition and results of operations.


Decommissioning. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. For a discussion of matters regarding the adequacy of Generation’s nuclear decommissioning trust funds to meet its decommissioning obligations, the obligations imposed on Generation related to the potential excess or shortfall of trust funds, the impact on Generation’s accounting for its former ComEd units as a result of a shortfall of trust funds and other matters related to Generation’s trust funds and decommissioning obligations, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Exelon Corporation, Executive Overview, Capital and Credit Market Crisis; ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates, Nuclear Decommissioning Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Notes 8 and 12 of the Combined Notes to Consolidated Financial Statements.


Dresden Unit 1, Peach Bottom Unit 1 and Zion (Zion Station), a two-unit nuclear generation station, have ceased power generation. SNF at Dresden Unit 1 is currently being stored in dry cask storage until a permanent repository under the Nuclear Waste Policy Act of 1982 (NWPA) is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. SNF at Zion Station is currently stored in on-site storage pools. Generation’s liability to decommission Dresden Unit 1, Peach Bottom Unit 1 and Zion Station was $759 million at December 31, 2008. As of December 31, 2008, nuclear decommissioning trust funds set aside to pay for these obligations were $995 million.


Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement with Energy Solutions, Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, LLC (ZionSolutions) for decommissioning of Zion Station, which is located in Zion, Illinois and which ceased operation in 1998.


If the various closing conditions under the Asset Sale Agreement are satisfied and the transaction is completed, Generation will transfer to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in nuclear decommissioning trusts (approximately $749 million as of December 31, 2008). In consideration for Generation’s transfer of those assets,




ZionSolutions will assume decommissioning and other liabilities associated with Zion Station. For accounting purposes, based on agreements signed to date, the decommissioning funds are expected to continue to be recorded on Generation’s balance sheet and the transferred decommissioning obligation is expected to be replaced with a payable to ZionSolutions on Generation’s balance sheet. ZionSolutions will take possession and control of the land associated with Zion Station pursuant to a Lease Agreement with Generation, to be executed at the closing. Under the Lease Agreement, ZionSolutions will commit to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the spent nuclear fuel currently held in spent fuel pools at Zion Station. Rent payable under the Lease Agreement will be $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask spent nuclear fuel storage facility. To reduce any potential risk of default by EnergySolutions or ZionSolutions, EnergySolutions is required to provide a $200 million letter of credit to be used to fund decommissioning costs in case of a shortfall of decommissioning funds following specified failures of performance. EnergySolutions has also provided a performance guarantee and will enter into other agreements that will provide rights and remedies for Generation in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all low level waste volume of Zion Station. However, if the resources of EnergySolutions Inc. and its subsidiaries are inadequate to complete required decommissioning work, Generation may be required to complete the work at its own expense.


ZionSolutions and Generation will also enter into a Put Option Agreement pursuant to which ZionSolutions will have the option to transfer the remaining Zion Station assets and any associated liabilities back to Generation upon completion of all required decommissioning and other work at Zion Station. The purchase price payable under the Put Option Agreement is $1.00 plus the assumption of associated liabilities.


Completion of the transactions contemplated by the Asset Sale Agreement is subject to the satisfaction of a number of closing conditions, including approval of the license transfer from the NRC, which is expected in early 2009. On July 14, 2008, the IRS issued a private letter ruling indicating that the proposed transfer of the decommissioning funds would be treated as non-taxable to both Generation and EnergySolutions. Prior to completion of the transaction, EnergySolutions must submit a budget that demonstrates that the required work can be completed on schedule for the amount of funds held in decommissioning trusts. On October 14, 2008, EnergySolutions announced that it intended to defer the transfer of the Zion Station assets until after the financial markets stabilize and EnergySolutions reaffirms that there is sufficient value in the Zion decommissioning trust funds to ensure the success of the Zion early decommissioning project. To date, this continues to be EnergySolutions’s intention. Pursuant to their agreement, EnergySolutions and Generation have until December 31, 2009, to close the transaction. Generation believes that accelerated decommissioning will make the land available for other uses earlier than originally thought possible, and can be completed cost effectively for the amounts that were collected from ratepayers and deposited into the nuclear decommissioning trust funds for Zion Station.









The following table shows sources of electric supply in GWhs for 2008 and estimated for 2009:


     Source of Electric Supply (a)
         2008          2009   (Est.)

Nuclear units

   139,342    138,897

Purchases—non-trading portfolio

   26,263    31,215

Fossil and hydroelectric units

   10,569    11,223

Total supply

   176,174    181,335


(a) Represents Generation’s proportionate share of the output of its generating plants.


The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its obligations for sales to other utilities, including to ComEd and PECO, and some of Generation’s retail business requirements.




The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2010. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2011. All of Generation’s enrichment requirements have been contracted through 2010. Contracts for fuel fabrication have been obtained through 2012. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuel requirements of its nuclear units.


Approximately 13% of Generation’s uranium enrichment services forward commitments are with European suppliers. In January 2002, the U.S. International Trade Commission determined that USEC, Inc. was “materially injured or threatened with material injury” by low-enriched uranium exported by European suppliers and as a result, the U.S. Department of Commerce assessed countervailing and anti-dumping duties against the European suppliers. Both USEC, Inc. and the European suppliers appealed these decisions. On January 27, 2009, the U.S. Supreme Court issued a ruling regarding the ongoing trade action that permitted the U.S. Department of Commerce to impose anti-dumping duties on low enriched uranium from Europe. As a result of these actions, Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.


Coal is procured for coal-fired plants primarily through annual supply contracts, with the remainder supplied through either short-term contracts or spot-market purchases.


Natural gas is procured for gas-fired plants through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or natural gas as fuel. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.


Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates and Note 9 of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.




Capital Expenditures


Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2009 are as follows:



(in millions)


Production plant

   $ 1,060

Nuclear fuel (a)



   $ 1,957


(a) Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant.





lobal Climate Change


Exelon believes the evidence of global climate change is compelling and that the energy industry, though not alone, is a significant contributor to the human-caused emissions of greenhouse gases (GHGs) that many in the scientific community believe contribute to global climate change. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, hydroelectric and landfill gas), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide (CO2) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions from the direct combustion of fossil fuels, primarily at its generating plants; CO2, methane and nitrous oxide are all emitted in this process, with CO2 representing the largest portion of these GHG emissions. GHG emissions from Generation’s combustion of fossil fuels represent approximately 90% of Exelon’s total GHG emissions; this is also a highly variable component of its GHG emissions to forecast due to the primarily intermediate and peaking profile of Exelon’s fossil generating fleet. However, only approximately 6% of Exelon’s total electric supply is provided by its fossil fuel generating plants. Other GHG emission sources at Exelon include natural gas (methane) leakage on the gas pipeline system and the coal piles at its generating plants, sulfur hexafluoride (SF6) leakage in its electric operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and usage of electricity in its facilities. Despite its small carbon footprint, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and by mandatory programs to reduce GHG emissions.


Physical Risks. Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena, could affect some, or all, of Exelon’s operations. Exelon is currently evaluating potential physical risk issues to its operations resulting from climate change, as well as potential options to manage those risks.


In general, weather patterns and the related impact on electricity and gas usage affect Exelon’s results of operations. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures in the winter adversely affect the usage of energy and resulting revenues. Extreme weather conditions may stress ComEd’s and PECO’s transmission and distribution systems, resulting in increased maintenance and capital expenditures and challenging their ability to meet peak customer




demand, thereby causing detrimental effects on ComEd’s and PECO’s operations. ComEd and PECO take steps to reduce extreme peak demand by implementing a number of programs, such as demand response and energy efficiency programs that will help to defer the need for additional transmission and distribution investment and support system reliability. In addition, ComEd and PECO analyze and plan using worst case scenarios and incorporate contingencies into their planning for extreme weather conditions.


Generation’s operations are also affected by weather, both in terms of demand for electricity and in operating conditions. The effects of unusually warm or cold weather on Generation’s results of operations depend on the nature of its market position at the time of the unusual weather. Generation plans its business based upon normal weather assumptions while performing analysis and necessary planning for severe weather driven scenarios. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractual requirements. Extreme weather conditions or storms may affect the availability of generation and transmission capacity, limiting Generation’s ability to source or deliver power to where it is needed. These conditions, which cannot be reliably predicted, may have an adverse effect by requiring Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak. Generation incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.


Additionally, Exelon is affected by the occurrence of extreme weather events such as hurricanes and storms in its service territories and throughout the United States. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within Exelon’s service areas can also directly affect Exelon’s capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for Exelon’s continued operation, particularly the cooling of generating units. Exelon is engaged in several projects to identify opportunities for increasing water use efficiency, reducing water supply vulnerabilities and reducing water supply costs.


Climate Change Legislation. Various stakeholders, including Exelon, legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors are considering ways to address the climate change issue. Mandatory programs to reduce GHG emissions are likely to evolve in the future. If these programs become effective, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or procure emission allowances or credits.


Numerous bills have been introduced in Congress that address climate change from different perspectives, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon emissions and incentives to develop low-carbon technology. In addition to potential Federal legislation to directly regulate GHG emissions, it is possible that Congress may also consider other legislation with perceived GHG reduction benefits such as the establishment of Federal renewable energy portfolio standards (RPS).


Exelon supports the enactment, through Federal legislation, of a cap-and-trade program for GHG emissions that is mandatory, economy-wide and designed in a way to limit potential harm to the economy and protect consumers. Exelon believes that any mechanism for allocation of GHG emission allowances should include significant free grants of allowances to electric (and potentially gas) distribution companies to help offset the cost impact of GHG regulation to the end-use consumer. Over the last few years, Exelon has worked with other businesses and environmental organizations that participate in the United States Climate Action Partnership to support the development of an integrated




package of recommendations for the Federal government to address the climate change issue through Federal legislation, including aggressive emission reduction targets for total U.S. emissions and robust cost containment measures to ensure that program costs are reasonable.


In June 2008, the Senate failed to pass the Lieberman-Warner America’s Climate Security Act, which would have created an economy-wide cap-and-trade program. The America’s Climate Security Act would reduce emissions by 70% from 2005 levels from covered sources by 2050, create a Carbon Market Efficiency Board to control costs of the program and initially auction 26.5% of the allowances rising to 69.5% in 2031. The bill gives 19% of the allowances to electric generators based on their heat input and 9% of allowances to electric local distribution companies for the benefit of their customers. The allowances to generators phase out to zero by 2031. Multiple bills were introduced in the House of Representatives but no action was taken on any of them either in the Energy and Commerce Committee or by the full House of Representatives. In late 2008, then-Chairman Dingell released a discussion draft for cap-and-trade legislation with Representative Boucher. The discussion draft would reduce emissions by 80% from 2005 levels by 2050. The discussion draft presented four options for how to allocate allowances. President Obama has stated that he favors climate legislation that would reduce greenhouse gas emissions by 80% by 2050 and that he prefers that 100% of allowances be auctioned.


Legislative efforts in Illinois and Pennsylvania related to climate change have focused primarily on energy efficiency, demand response and renewable energy initiatives. The Illinois Settlement Legislation enacted in 2007 requires electric utilities to use cost-effective energy efficiency resources to meet specific incremental annual energy savings goals. The Illinois Settlement Legislation also requires procurement plans of electric utilities in Illinois to include cost-effective renewable energy resources that meet a defined portion of total electricity supplied to retail customers. In Pennsylvania, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act) mandated that, beginning in 2007 or at the end of an electric distribution company’s restructuring period, specified percentages of electric energy sold by the electric distribution company or the electric generation supplier to Pennsylvania retail electric customers must come from alternative energy resources. The Pennsylvania Climate Change Act (PCCA) was also signed into law in July 2008. The PCCA requires, among other things, that a Climate Change Advisory Committee be formed, that a report on the potential impact of climate change in Pennsylvania be developed, that the Pennsylvania Department of Environmental Protection (PA DEP) develop a GHG inventory for Pennsylvania, that a voluntary GHG registry be identified, and that PA DEP, in consultation with the Climate Change Advisory Committee, develop a Climate Change Action Plan for Pennsylvania to be reviewed with the Pennsylvania General Assembly. In October 2008, Act 129 became effective and requires that Pennsylvania electric utility companies meet energy-conservation and demand-reduction targets, beginning in 2011, to enhance Pennsylvania’s energy independence and enable programs to help consumers manage their energy use.


On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U. S. Environmental Protection Agency holding that CO2 and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative provide a reasonable explanation why GHG emissions should not be regulated. Possible outcomes from this decision include regulation of GHG emissions not only from motor vehicles but also from manufacturing plants, including electric generation, transmission and distribution facilities, under a new EPA rule and Federal or state legislation. In response to the Supreme Court decision, on July 11, 2008, the EPA issued an Advance Notice of Proposed Rulemaking (ANPR) and is currently considering public comments made on analyses and policy alternatives regarding GHG effects and regulation under the Clean Air Act. This deferred any regulation of GHGs under the Clean Air Act. The issue of GHG regulation will likely be addressed in the new presidential administration, whether by regulation under the Clean Air Act or by




new and comprehensive Federal legislation. Due to the uncertainty as to any of these potential outcomes, Exelon cannot estimate the effect of the decision on its operations and its future competitive position, results of operations, earnings, cash flows and financial position.


At a regional level, on August 24, 2005, the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by Northeastern and Mid-Atlantic states to reduce CO2 emissions, released a program proposal. The RGGI Memorandum of Understanding (MOU) is an agreement to stabilize aggregate CO2 emissions from power plants in participating states at current levels from 2009 to 2015. Reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant COemissions. As of December 31, 2008, states participating in the RGGI MOU include Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont. On August 15, 2006, the RGGI model rule was finalized, and RGGI member states that have not already done so are currently in the process of adopting state-level rules to implement the program starting in 2009. On September 26, 2008, six of the ten RGGI states participated in the first auction of CO2 allowances under the program. Approximately 12.5 million tons of CO2 allowances were auctioned. Generation owns a small amount of affected peaking and intermediate generating capacity in the RGGI region, including Maine, Massachusetts and New Jersey. On November 15, 2007, six Midwest state Governors (Illinois, Iowa, Kansas, Michigan, Minnesota, Wisconsin) signed the Midwestern Greenhouse Gas Accord (the Accord). Under the Accord, an inter-state work group is to be formed to establish a Midwestern GHG Reduction Program that will: (1) establish GHG reduction targets and timeframes consistent with member state targets; (2) develop a market-based and multi-sector cap-and-trade program to help achieve GHG reductions; and (3) develop other mechanisms and policies to assist in meeting GHG reduction targets (e.g. a low carbon fuel standard). All undertakings of the Accord are to be completed within 30 months after its effective date, including the development of a proposed cap-and-trade agreement and model rule within 12 months.


At the international level, the United States is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) and became effective for signatories on February 16, 2005. The United Nations’ Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted, which identifies a work group, process and timeline for the consideration of possible post-2012 international actions to further address climate change. The United States is expected to participate in this process. Recommendations will be reviewed at the UNFCCC meeting in 2009.


At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legal or regulatory requirements on its businesses.


Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change, nuclear power as well as other virtually non-GHG emitting power will play a pivotal role. As a result, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon believes that the significance of its low GHG emission profile can only grow as policymakers take action to address global climate change.


Despite Exelon’s low GHG emission intensity and the absence of a mandatory national program in the United States, Exelon is actively engaged in voluntary reduction efforts. Exelon announced on May 6, 2005 that it had established a voluntary goal to reduce its GHG emissions by 8% from 2001 levels by the end of 2008. The 8% reduction goal represents a decrease of an estimated 1.3 million metric tons of GHG emissions. Exelon has incorporated recognition of GHG emissions and their potential cost into its business analyses as a means to promote internal investment in activities that produce fewer GHG emissions. Exelon made this pledge under the EPA’s Climate Leaders program, a




voluntary industry-government partnership addressing climate change. As of December 31, 2008, Exelon had achieved its 2008 voluntary GHG reduction goal through its planned GHG management efforts, including the previous closure of older, inefficient fossil-fueled power plants, reduced leakage of SFand methane, increased use of renewable energy and its energy efficiency initiatives. The cost of achieving the voluntary GHG emissions reduction goal did not have a material effect on Exelon’s future competitive position, results of operations, earnings, financial position or cash flows.


On July 15, 2008, Exelon announced a comprehensive business and environmental plan. The plan, Exelon 2020, details an enterprise-wide approach and a host of initiatives being pursued by Exelon to reduce Exelon’s GHG emissions and that of its customers, communities, suppliers and markets. Exelon 2020 sets a goal for Exelon to reduce, offset, or displace more than 15 million metric tons of GHG emissions per year by 2020, which is more than Exelon’s current annual carbon footprint.


Through Exelon 2020, Exelon is pursuing three broad strategies: reducing or offsetting its own carbon footprint, helping customers and communities reduce their GHG emissions, and offering more low-carbon electricity in the marketplace. Initiatives to reduce Exelon’s own carbon footprint include reducing building energy consumption by 25%, reducing the vehicle fleet emissions, improving the efficiency of the generation and delivery system for electricity and natural gas, and developing an industry-leading green supply chain. Plans to help customers reduce their GHG emissions include ComEd’s new portfolio of energy efficiency programs, a similar portfolio of energy efficiency programs in development at PECO to meet the requirements of the recently enacted PA Act 129, the implementation of smart-meters and real-time pricing programs and a broad array of communication initiatives to increase customer awareness of approaches to manage their energy consumption. Finally, Exelon will offer more low-carbon electricity in the marketplace by increasing its investment in renewable power, adding capacity to existing nuclear plants through uprates, and through the potential addition of new low-carbon natural gas and nuclear generation.


Exelon is committed to achieving the Exelon 2020 goal but also recognizes that the changing economy and market outlook may require it to refine or alter the timing of some of these initiatives and update the 2020 roadmap accordingly. The anticipated economic stimulus package currently being considered in Congress and other new energy policies will also likely have an impact on initiatives under the plan.


Exelon has incorporated Exelon 2020 into the company’s overall business plans and has an organized implementation effort underway. This implementation effort includes a periodic review and refinement of Exelon 2020 initiatives in light of changing market conditions. The amount of expenditures to implement the plan will depend on economic and policy developments, and will be made on a project-by-project basis in accordance with Exelon’s normal project evaluation standards.



As further discussed below, Generation also currently procures uranium concentrates through long-term contracts. Approximately 60% of the requirements from 2009 through 2013 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Management continues to closely monitor the status of Generation’s counterparties and will take action, as appropriate, to further manage its counterparty credit risk.







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