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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2008
Commission file number 1-14287
USEC Inc.
 	 	 	
Delaware
(State of incorporation)	 	52-2107911
(I.R.S. Identification No.)	
2 Democracy Center
6903 Rockledge Drive, Bethesda, Maryland 20817
(301) 564-3200
Securities registered pursuant to Section 12(b) of the Act:
 	 	 	
Title of Each Class	 	Name of Exchange on Which Registered	
Common Stock, par value $.10 per share
Preferred Stock Purchase Rights	 	New York Stock Exchange
New York Stock Exchange	
Securities registered pursuant to Section 12(g) of the Act: None
     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
               Yes o   No þ
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
               Yes o   No þ
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
               Yes þ   No o
     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ	Accelerated filer o 	Non-accelerated filer o
(Do not check if a smaller reporting company)	Smaller reporting company  o	
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
               Yes o   No þ
     The aggregate market value of Common Stock held by non-affiliates of the registrant calculated by reference to the closing price of the registrant’s Common Stock as reported on the New York Stock Exchange as of June 30, 2008, was $676.4 million. As of January 31, 2009, there were 111,349,000 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 for the annual meeting of shareholders to be held on April 30, 2009, are incorporated by reference into Part III.

 

 
TABLE OF CONTENTS
 	 	 	 	 	 	 	 	
 	 	 	 	Page	 	
 	 	PART I 	 	 	 	 	 	
Items 1 and 2.	 	Business and Properties	 	 	3	 	 	
Item 1A.	 	Risk Factors	 	 	27	 	 	
Item 1B.	 	Unresolved Staff Comments	 	 	46	 	 	
Item 3.	 	Legal Proceedings	 	 	46	 	 	
Item 4.	 	Submission of Matters to a Vote of Security Holders	 	 	46	 	 	
 	 	Executive Officers of the Company	 	 	47	 	 	
 	 	 	 	 	 	 	 	
 	 	PART II 	 	 	 	 	 	
Item 5.	 	Market for Registrant’s Common Equity and Related Stockholder Matters	 	 	49	 	 	
Item 6.	 	Selected Financial Data	 	 	52	 	 	
Item 7.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	54	 	 	
Item 7A.	 	Quantitative and Qualitative Disclosures about Market Risk	 	 	82	 	 	
Item 8.	 	Consolidated Financial Statements and Supplementary Data	 	 	82	 	 	
Item 9.	 	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	 	 	82	 	 	
Item 9A.	 	Controls and Procedures	 	 	82	 	 	
Item 9B.	 	Other Information	 	 	83	 	 	
 	 	 	 	 	 	 	 	
 	 	PART III 	 	 	 	 	 	
Item 10.	 	Directors, Executive Officers and Corporate Governance	 	 	84	 	 	
Item 11.	 	Executive Compensation	 	 	84	 	 	
Item 12.	 	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	 	84	 	 	
Item 13.	 	Certain Relationships and Related Transactions, and Director Independence	 	 	84	 	 	
Item 14.	 	Principal Accountant Fees and Services	 	 	84	 	 	
 	 	 	 	 	 	 	 	
 	 	PART IV 	 	 	 	 	 	
Item 15.	 	Exhibits and Financial Statement Schedules	 	 	85	 	 	
Signatures	 	 	86	 	 	
Consolidated Financial Statements	 	 	87 - 125	 	 	
Glossary	 	 	126	 	 	
Exhibit Index	 	 	129	 	 	
 Exhibit 10.36	
 Exhibit 10.37	
 Exhibit 21	
 Exhibit 23.1	
 Exhibit 31.1	
 Exhibit 31.2	
 Exhibit 32	
 Exhibit 99.2	
 
This annual report on Form 10-K, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, contains “forward-looking statements” — that is, statements related to future events. In this context, forward-looking statements may address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “will” and other words of similar meaning. Forward-looking statements by their nature address matters that are, to different degrees, uncertain. For USEC, particular risks and uncertainties that could cause our actual future results to differ materially from those expressed in our forward-looking statements include, but are not limited to: risks related to the deployment of the American Centrifuge technology, including our ability to meet targets for performance, cost and schedule and to obtain financing; our success in obtaining a loan guarantee for the American Centrifuge Plant and the impact of delays in financing on project spending, cost and schedule; uncertainty regarding the cost of electric power used at our gaseous diffusion plant; our dependence on deliveries under the Russian Contract and on a single production facility; our inability under most existing long-term contracts to directly pass on to customers increases in our costs; the decrease or elimination of duties charged on imports of foreign-produced low enriched uranium; pricing trends in the uranium and enrichment markets and their impact on our profitability; changes
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to, or termination of, our contracts with the U.S. government and changes in U.S. government priorities and the availability of government funding, including loan guarantees; the impact of government regulation; the outcome of legal proceedings and other contingencies (including lawsuits and government investigations or audits); the competitive environment for our products and services; changes in the nuclear energy industry; the potential impact of volatile financial market conditions on our pension assets and credit and insurance facilities; and other risks and uncertainties discussed in this and our other filings with the Securities and Exchange Commission. Revenue and operating results can fluctuate significantly from quarter to quarter, and in some cases, year to year. For a discussion of these risks and uncertainties and other factors that may affect our future results, please see Item 1A of this report entitled “Risk Factors.” We do not undertake to update our forward-looking statements except as required by law.
Items 1 and 2. Business and Properties
Overview
     USEC, a global energy company, is a leading supplier of low enriched uranium (“LEU”) for commercial nuclear power plants. LEU is a critical component in the production of nuclear fuel for reactors to produce electricity. We:
 	•	 	supply LEU to both domestic and international utilities for use in about 150 nuclear reactors worldwide;	
 	 	 	 	
 	•	 	are deploying what we anticipate will be the world’s most advanced uranium enrichment technology, known as the American Centrifuge;	
 	 	 	 	
 	•	 	are the exclusive executive agent for the U.S. government under a nuclear nonproliferation program with Russia, known as Megatons to Megawatts;	
 	 	 	 	
 	•	 	perform contract work for the U.S. Department of Energy (“DOE”) and its contractors at the Paducah and Portsmouth gaseous diffusion plants (“GDPs”); and	
 	 	 	 	
 	•	 	provide transportation and storage systems for spent nuclear fuel and provide nuclear and energy consulting services.	
     USEC Inc. is organized under Delaware law. USEC was a U.S. government corporation until July 28, 1998, when the company completed an initial public offering of common stock. In connection with the privatization, the U.S. government transferred all of its interest in the business to USEC, with the exception of certain liabilities from prior operations of the U.S. government. References to “USEC” or “we” include USEC Inc. and its wholly owned subsidiaries as well as the predecessor to USEC unless the context otherwise indicates. A glossary of certain terms used in our industry and herein is included in Part IV of this annual report.
Uranium and Enrichment
     In its natural state, uranium is principally comprised of two isotopes: uranium-235 (“U235”) and uranium-238 (“U 238 ”). U 238  is the more abundant isotope, but it is not readily fissionable in light water nuclear reactors. U 235 is fissile, but its concentration in natural uranium is only 0.711% by weight. Most commercial nuclear power reactors require LEU fuel with a U 235  concentration greater than natural uranium and up to 5% by weight. Uranium enrichment is the process by which the concentration of U 235  is increased to that level.
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     The following outlines the steps for converting natural uranium into LEU fuel, commonly known as the nuclear fuel cycle:
 	•	 	Mining and Milling — Natural, or unenriched, uranium is removed from the earth in the form of ore and then crushed and concentrated.	
 	 	 	 	
 	•	 	Conversion — Uranium concentrates are combined with fluorine gas to produce uranium hexafluoride (“UF 6 ”), a solid at room temperature and a gas when heated. UF 6  is shipped to an enrichment plant.	
 	 	 	 	
 	•	 	Enrichment — UF6 is enriched in a process that increases the concentration of the U235 isotope in the UF6 from its natural state of 0.711% up to 5%, which is usable as a fuel for light water commercial nuclear power reactors. Depleted uranium is a by-product of the uranium enrichment process. The standard measure of uranium enrichment is a separative work unit (“SWU”). A SWU represents the effort that is required to transform a given amount of natural uranium into two streams of uranium, one enriched in the U 235  isotope and the other depleted in the U 235  isotope. SWUs are measured using a standard formula derived from the physics of uranium enrichment. The amount of enrichment deemed to be contained in LEU under this formula is commonly referred to as its SWU component and the quantity of natural uranium deemed to be used in the production of LEU under this formula is referred to as its uranium component.	
 	 	 	 	
 	•	 	Fuel Fabrication — LEU is converted to uranium oxide and formed into small ceramic pellets by fabricators. The pellets are loaded into metal tubes that form fuel assemblies, which are shipped to nuclear power plants.	
 	 	 	 	
 	•	 	Nuclear Power Plant — The fuel assemblies are loaded into nuclear reactors to create energy from a controlled chain reaction. Nuclear power plants generate over 15% of the world’s electricity.	
 	 	 	 	
 	•	 	Consumers — Businesses and homeowners rely on the steady, baseload electricity supplied by nuclear power and value its clean air qualities.	

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     We produce or acquire LEU from two principal sources. We produce LEU at the Paducah GDP in Paducah, Kentucky, and we acquire LEU by purchasing the SWU component of LEU from Russia under the Megatons to Megawatts program.
Products and Services
     Low Enriched Uranium
     The majority of our customers are domestic and international utilities that operate nuclear power plants. Our revenue is derived primarily from:
 	•	 	sales of the SWU component of LEU,	
 	 	 	 	
 	•	 	sales of both the SWU and uranium components of LEU, and	
 	 	 	 	
 	•	 	sales of uranium.	
     Our agreements with electric utilities are primarily long-term, fixed-commitment contracts under which our customers are obligated to purchase a specified quantity of SWU or uranium from us or long-term requirements contracts under which they are obligated to purchase a percentage of their SWU requirements from us. Under requirements contracts, customers only make purchases if the reactor has requirements. The timing of requirements is associated with reactor refueling outages.
      Contract Services
     We perform contract work for DOE and DOE contractors at the Paducah and Portsmouth GDPs, including infrastructure support services and maintenance of the Portsmouth GDP in a state of “cold shutdown” in preparation for decontamination and decommissioning.
     Through our subsidiary NAC, we are a leading provider of nuclear energy services and technologies, specializing in:
 	•	 	design, fabrication and implementation of spent nuclear fuel technologies,	
 	 	 	 	
 	•	 	nuclear materials transportation, and	
 	 	 	 	
 	•	 	nuclear fuel cycle consulting services.	
Revenue by Geographic Area, Major Customers and Segment Information
     Revenue attributed to domestic and foreign customers, including customers in a foreign country representing 10% or more of total revenue, follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
United States	 	$	1,212.5	 	 	$	1,310.6	 	 	$	1,109.5	 	
Foreign:	 	 	 	 	 	 	 	 	 	 	 	 	
Japan	 	 	242.6	 	 	 	274.7	 	 	 	389.8	 	
Other	 	 	159.5	 	 	 	342.7	 	 	 	349.3	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	402.1	 	 	 	617.4	 	 	 	739.1	 	
 	 	 	 	 	 	 	 	 	 	
 	 	$	1,614.6	 	 	$	1,928.0	 	 	$	1,848.6	 	
 	 	 	 	 	 	 	 	 	 	
     Our 10 largest utility customers represented 57% of revenue and our three largest utility customers represented 30% of revenue in 2008. Revenue from two domestic customers, Exelon Corporation and Entergy Corporation, each represented more than 10%, but less than 15%, of revenue in 2008. Revenue from U.S. government contracts represented 12% of revenue in 2008, 9% of revenue in 2007 and 10% of revenue in 2006. No other customer represented more than 10% of revenue. Reference is made to segment information reported in note 17 to the consolidated financial statements.
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SWU and Uranium Backlog
     Backlog is the aggregate dollar amount of SWU and uranium that we expect to sell in future periods under contracts with customers. At December 31, 2008, we had contracts with customers aggregating an estimated $6.9 billion, including $1.7 billion expected to be delivered in 2009, compared with $6.5 billion at December 31, 2007. Backlog is partially based on customers’ estimates of their fuel requirements and other assumptions including our estimates of selling prices, which are subject to change. Prices may be adjusted based on SWU or uranium market prices prevailing at the time of delivery. Pricing elements may include escalation based on a general inflation index or a power price index. We utilize external composite forecasts of future market prices and inflation rates in our pricing estimates.
Gaseous Diffusion Plants
     Two existing technologies are currently used commercially to enrich uranium for nuclear power plants: gaseous diffusion and gas centrifuge. We currently use the older gaseous diffusion technology and are deploying gas centrifuge technology to replace our gaseous diffusion operations. See “Business and Properties — The American Centrifuge Plant.”
     Gaseous Diffusion Process
     The gaseous diffusion process separates the lighter U235 isotope from the heavier U238. The fundamental building block of the gaseous diffusion process is known as a stage, consisting of a compressor, a converter, a control valve and associated piping. Compressors driven by large electric motors are used to circulate the process gas and maintain flow. Converters contain porous tubes known as a barrier through which process gas is diffused. Stages are grouped together in series to form an operating unit called a cell. A cell is the smallest group of stages that can be removed from service for maintenance. Gaseous diffusion plants are designed so that cells can be taken off line with little or no interruption in the process.
     The process begins with the heating of solid UF6 to form a gas that is forced through the barrier. Because U 235 is lighter than U  238 , it moves through the barrier more easily. As the gas moves, the two isotopes are separated, increasing the U  235 concentration and decreasing the concentration of U  238  in the finished product. The gaseous diffusion process requires significant amounts of electric power to push uranium through the barrier.
     Paducah GDP
     We operate the Paducah GDP located in Paducah, Kentucky. The Paducah GDP consists of four process buildings and is one of the largest industrial facilities in the world. The process buildings have a total floor area of 150 acres, and the site covers 750 acres. We estimate that the maximum capacity of the existing equipment is about 8 million SWU per year. In 2008, we produced approximately 6.5 million SWU at the Paducah GDP for both LEU production and underfeeding uranium. The Paducah GDP has been certified by the NRC to produce LEU up to an assay of 5.5% U  235 .
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     Portsmouth GDP
     We ceased uranium enrichment operations at the Portsmouth GDP, located in Piketon, Ohio, in 2001. Under contract with DOE, we maintain the Portsmouth GDP in a state of “cold shutdown” in preparation for a DOE decontamination and decommissioning program. DOE and USEC have periodically extended the Portsmouth GDP cold shutdown contract, most recently through April 30, 2009. DOE has announced its intention to negotiate a sole-source extension of the cold shutdown contract through September 30, 2010.
      Lease of Gaseous Diffusion Plants
     We lease the Paducah and Portsmouth GDPs from DOE. The lease covers most, but not all, of the buildings and facilities relating to gaseous diffusion activities. Major provisions of the lease follow:
 	•	 	except as provided in the 2002 DOE-USEC Agreement (described under “Business and Properties — 2002 DOE-USEC Agreement and Related Agreements with DOE”), we have the right to renew the lease at either plant indefinitely in six-year increments and can adjust the property under lease to meet our changing requirements. The current lease term expires in 2016;	
 	 	 	 	
 	•	 	we may leave the property in an “as is” condition at termination of the lease, but must remove wastes we generate and must place the plants in a safe shutdown condition;	
 	 	 	 	
 	•	 	the U.S. government is responsible for environmental liabilities associated with plant operations prior to July 28, 1998 except for liabilities relating to the disposal of some identified wastes generated by USEC and stored at the plants;	
 	 	 	 	
 	•	 	DOE is responsible for the costs of decontamination and decommissioning of the plants;	
 	 	 	 	
 	•	 	title to capital improvements not removed by us will transfer to DOE at the end of the lease term, and if we elect to remove any capital improvements, we are required to pay any increases in DOE’s decontamination and decommissioning costs that are a result of our removing the capital improvements;	
 	 	 	 	
 	•	 	DOE must indemnify us for costs and expenses related to claims asserted against us or incurred by us arising out of the U.S. government’s operation, occupation, or use of the plants prior to July 28, 1998; and	
 	 	 	 	
 	•	 	DOE must indemnify us against claims for public liability (as defined in the Atomic Energy Act of 1954, as amended) from a nuclear incident or precautionary evacuation in connection with activities under the lease. Under the Price- Anderson Act, DOE’s financial obligations under the indemnity are capped at $12.5 billion for each nuclear incident or precautionary evacuation occurring inside the United States.	
     In December 2006, we signed a lease agreement with DOE for our long-term use of facilities at the Portsmouth GDP in Piketon for the American Centrifuge Plant. The lease for these facilities and other support facilities is a stand-alone amendment to our current lease with DOE for the GDP facilities. Further details are provided in “Business and Properties — The American Centrifuge Plant”.
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Raw Materials
     Electric Power
     The gaseous diffusion process uses significant amounts of electric power to enrich uranium. Costs for electric power are approximately 70-75% of production costs at the Paducah GDP. In 2008, the power load at the Paducah GDP averaged 1,680 megawatts. We purchase most of the electric power for the Paducah GDP under a power purchase agreement with Tennessee Valley Authority (“TVA”) that expires May 31, 2012. Pricing under the TVA power contract consisted of a summer and a non-summer base energy price through May 31, 2008. Beginning June 1, 2008, the price consists of a year-round base energy price that increases moderately based on a fixed, annual schedule. All prices are subject to a fuel cost adjustment provision to reflect changes in TVA’s fuel costs, purchased power costs, and related costs. The impact of the fuel cost adjustment has been negative for USEC, imposing an average increase over base contract prices of about 15% in 2008 and 8% in 2007. The impact of future fuel cost adjustments, which are substantially influenced by coal prices, purchased power costs and hydroelectric power generation, is uncertain and our cost of power could fluctuate in the future above or below the agreed increases in the base energy price. We expect the fuel cost adjustment to continue to cause our purchase cost to remain above base contract prices. The future impact may be greater but is difficult to predict given uncertainty in energy prices.
     The quantity of power purchases under the TVA contract generally ranges from 300 megawatts in the summer months (June — August) to up to 2,000 megawatts in the non-summer months. We supplement the TVA contract during the summer months with additional power purchased at market-based prices. Beginning June 1, 2010 through the expiration of the contract on May 31, 2012, the quantity of non-summer power purchases will be reduced to a maximum of 1,650 megawatts at all hours. This is designed to provide a transition for the TVA power system because of the significant amount of power we purchase. We expect to supplement the TVA contract with additional power purchases beginning June 1, 2010 and will be evaluating possible sources of power for delivery after May 31, 2012.
     We are required to provide financial assurance to support our payment obligations to TVA. These include a letter of credit and weekly prepayments based on TVA’s estimate of the price and our usage of power.
      Uranium
     Natural uranium is the feedstock in the production of LEU at the Paducah GDP. In 2008, the plant used the equivalent of approximately 8 million kilograms of uranium in the production of LEU. Uranium is a naturally occurring element and is mined from deposits located in Canada, Australia and other countries. According to the World Nuclear Association, there are adequate measured resources of uranium to fuel nuclear power at current usage rates for at least 80 years.
     Mined uranium ore is crushed and concentrated and sent to a uranium conversion facility where it is converted to UF6, a form suitable for uranium enrichment. Two commercial uranium converters in North America, Cameco Corporation and ConverDyn, deliver and hold title to uranium at the Paducah GDP.
     Utility customers provide uranium to us as part of their enrichment contracts or purchase the uranium required to produce LEU from us. Customers who provide uranium to us generally do so by acquiring title to uranium from Cameco, ConverDyn and other suppliers at the Paducah GDP. At December 31, 2008, we held uranium to which title was held by customers and suppliers with a value of $3.8 billion based on published price indicators. The uranium is fungible and commingled with our uranium inventory. Title to uranium provided by customers generally remains with the customer until delivery of LEU, at which time title to LEU is transferred to the customer and we take title to the uranium. The uranium that we sell to utility customers comes from our uranium inventories, which includes uranium from underfeeding the enrichment process, purchases of uranium from third-party suppliers and uranium that we obtained from DOE prior to privatization.
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     The quantity of uranium used in the production of LEU is to a certain extent interchangeable with the amount of SWU required to enrich the uranium. Underfeeding is a mode of operation that uses or feeds less uranium. Underfeeding supplements our supply of uranium, but requires more SWU in the enrichment process, which requires more electric power. In producing the same amount of LEU, we vary our production process to underfeed uranium based on the economics of the cost of electric power relative to the prices of uranium and enrichment.
     Coolant
     The Paducah GDP uses Freon as the primary process coolant. The production of Freon in the United States was terminated in 1995 and Freon is no longer commercially available. We expect our current supply of Freon to be sufficient to support at least 10 years of continued operations at current use rates.
     GDP Equipment
     GDP equipment components (such as compressors, coolers, motors and valves) requiring maintenance are removed from service and repaired or rebuilt on site. Common industrial components, such as the breakers, condensers and transformers in the electrical system, are procured as needed. Some components and systems are no longer produced, and spare parts may not be readily available. In these situations, replacement components or systems are identified, tested, and procured from existing commercial sources, or the plants’ technical and fabrication capabilities are used to design and build replacements.
     Equipment utilization at the Paducah GDP averaged 97% in 2008 compared to 98% in 2007. Equipment utilization is based on a measure of cells in operation. The utilization of equipment is highly dependent on power availability and costs. We reduce equipment utilization and the related power load in the summer months when the cost of electric power is high. Equipment utilization is also affected by repairs and maintenance activities. The number of cells available for operation increased in 2008 due to the recovery of a number of cells which had been in standby for over 25 years.
Russian Contract (“Megatons to Megawatts”)
     We are the U.S. government’s exclusive executive agent (“Executive Agent”) in connection with a government-to-government nonproliferation agreement between the United States and the Russian Federation. Under the agreement, we have been designated by the U.S. government to order LEU derived from dismantled Soviet nuclear weapons. In January 1994, USEC signed a commercial agreement (“Russian Contract”) with a Russian government entity known as OAO Techsnabexport (“TENEX), to implement the program.
     We have agreed to purchase approximately 5.5 million SWU each calendar year for the remaining term of the Russian Contract through 2013. Over the life of the 20-year Russian Contract, we expect to purchase about 92 million SWU contained in LEU derived from 500 metric tons of highly enriched uranium. As of December 31, 2008, we had purchased 65 million SWU contained in LEU derived from 350 metric tons of highly enriched uranium, the equivalent of about 14,000 nuclear warheads. Purchases under the Russian Contract constitute approximately one-half of our supply mix. Prices are determined using a discount from an index of international and U.S. price points, including both long-term and spot prices. A multi-year retrospective view of the index is used to minimize the disruptive effect of short-term market price swings. Increases in these price points in
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recent years have resulted in increases to the index used to determine prices under the Russian Contract. On February 13, 2009, we entered into an amendment to the Russian Contract to revise the pricing methodology for the SWU component of LEU delivered in calendar years 2010 through 2013. Approval of both the U.S. government and the government of the Russian Federation is required for the amendment to become effective. The current pricing methodology uses a discount from an index of international and U.S. price points, including both long-term and spot prices. The new pricing methodology is intended to enhance the stability of future pricing for both parties through a formula that combines a different mix of price points and other pricing elements. We expect that prices paid under the Russian Contract, as amended, will continue to increase year over year, and that the total amount paid to the Russian Federation for the SWU component of the LEU delivered under the Russian Contract over the 20 year term of the contract will substantially exceed $8 billion by the time the contract is completed in 2013. Officials of the Russian government have announced that Russia will not extend the Russian Contract or the government-to-government agreement it implements, beyond 2013. Accordingly, we do not anticipate that we will purchase Russian SWU after 2013.
     Under the Russian Contract, we are obligated to provide to TENEX an amount of uranium equivalent to the uranium component of LEU delivered to us by TENEX, totaling about 9 million kilograms per year. We credit the uranium to an account at the Paducah GDP maintained on behalf of TENEX. TENEX holds the uranium or sells or otherwise exchanges this uranium in transactions with other suppliers or utility customers. From time to time, TENEX may take physical delivery of uranium supplied by a uranium converter that would otherwise deliver such uranium to us. Under these arrangements, the converter provides uranium to TENEX for shipment back to Russia, and the converter receives an equivalent amount of uranium in its account at the Paducah GDP.
     Under the terms of a 1997 memorandum of agreement between USEC and the U.S. government, we can be terminated, or resign, as the U.S. Executive Agent, or one or more additional executive agents may be named. Any new executive agent could represent a significant new competitor.
2002 DOE-USEC Agreement and Related Agreements with DOE
     On June 17, 2002, USEC and DOE signed an agreement in which both parties made long-term commitments directed at resolving issues related to the stability and security of the domestic uranium enrichment industry (such agreement, as amended, the “2002 DOE-USEC Agreement”). We and DOE have entered into subsequent agreements relating to these commitments and have amended the 2002 DOE-USEC Agreement. The following is a summary of material provisions and an update of activities under the 2002 DOE-USEC Agreement and related agreements:
      Megatons to Megawatts
     The 2002 DOE-USEC Agreement provides that DOE will recommend against removal, in whole or in part, of us as the U.S. Executive Agent under the government-to-government nonproliferation agreement between the United States and the Russian Federation as long as we order the specified amount of LEU from TENEX and comply with our obligations under the 2002 DOE-USEC Agreement and the Russian Contract.
     Remediating or Replacing Out-of-Specification Uranium
     Under the 2002 DOE-USEC Agreement, DOE was obligated to remediate or replace 9,550 metric tons of UF6 transferred to us from DOE prior to privatization that contained elevated levels of technetium. The contaminant put the uranium out-of-specification for commercial use. We operated facilities at the Portsmouth GDP under contract with DOE to process and remove technetium from the out-of-specification uranium, and in October 2006, the remediation project for USEC-owned uranium was completed. We also processed and removed technetium from out-of-specification uranium owned by DOE under an agreement with DOE entered into in December 2004. The remediation efforts were completed in September 2008 and we are currently performing services related to demobilization.
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     Domestic Enrichment Facilities
     Under the 2002 DOE-USEC Agreement, we agreed to operate the Paducah GDP at a production rate at or above 3.5 million SWU per year. Historically, we have operated at production rates significantly above this level, and in 2008, we produced approximately 6.5 million SWU at the Paducah GDP for both LEU production and underfeeding uranium. Production at Paducah may not be reduced below a minimum of 3.5 million SWU per year until six months before we have completed a centrifuge enrichment facility capable of producing LEU containing 3.5 million SWU per year. If the Paducah GDP is operated at less than the specified 3.5 million SWU in any given fiscal year, we may cure the defect by increasing LEU production to the 3.5 million SWU level in the next fiscal year. We may only use the right to cure once in each six-year lease period.
     If we do not maintain the requisite level of operations at the Paducah GDP and have not cured the deficiency, we are required to waive our exclusive rights to lease the Paducah and Portsmouth GDPs. If we cease operations at the Paducah GDP or lose our certification from the NRC, DOE may take actions it deems necessary to transition operation of the plant from us to ensure the continuity of domestic enrichment operations and the fulfillment of supply contracts. In either of the circumstances described in the preceding two sentences, DOE may be released from its obligations under the 2002 DOE-USEC Agreement. We will be deemed to have “ceased operations” at the Paducah GDP if we (1) produce less than 1 million SWU per year or (2) fail to meet specific maintenance and operational criteria established in the 2002 DOE-USEC Agreement.
     Advanced Enrichment Technology
     The 2002 DOE-USEC Agreement provides that we will begin operation of an enrichment facility using advanced enrichment technology in accordance with certain milestones. A discussion of our American Centrifuge uranium enrichment technology and those milestones is included under the caption “Business and Properties— The American Centrifuge Plant — Project Milestones under the 2002 DOE-USEC Agreement”.
     Other
     The 2002 DOE-USEC Agreement contains force majeure provisions that excuse our failure to perform under the agreement if such failure arises from causes beyond our control and without our fault or negligence.
The American Centrifuge Plant
     Since 2002, we have been developing and demonstrating a uranium enrichment gas centrifuge technology that we call the American Centrifuge. We are deploying this technology in the American Centrifuge Plant (“ACP”) being built in Piketon, Ohio. This technology was initially developed by DOE during the 1970s and 80s and successfully demonstrated, but was ultimately not commercially deployed for reasons unrelated to the technology itself. We have modified and improved this technology through the use of modern materials, advanced computer-aided design, digital controls and state-of-the-art manufacturing processes.
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     We are deploying the ACP to replace our gaseous diffusion uranium enrichment plant and to be well positioned to meet demand for LEU. Deploying the American Centrifuge technology will substantially reduce our power costs and modernize our production capacity, enabling us to stay competitive in the long term. Our baseline deployment schedule includes beginning initial commercial plant operations in 2010 and reaching an annual production capacity at the ACP of 3.8 million SWU per year at the end of 2012. However, as discussed below in “—Capital Requirements,” we have initiated steps to conserve cash and reduce the planned escalation of project construction and machine manufacturing activities until we gain greater clarity on potential funding for the project through the DOE Loan Guarantee Program. These steps are likely to increase the cost and extend the schedule for the project.
     We believe that the machine we deploy in the ACP will be the most advanced uranium enrichment machine in the world. We refer to our production centrifuge machine design as the AC100 series centrifuge machine. The AC100 series centrifuge machine is designed to produce 350 SWU per year, which output is substantially greater than our competitors’ machines. As discussed below in "—Value Engineering and Continued Technology Improvements,” we released an initial design for the AC100 machine in 2008. We anticipate releasing the design for the initial AC100 series machines in late March 2009 that will be deployed in the commercial plant. We will continue optimization and value-engineering efforts even after this design release.
     Our Marketing and Sales department has been engaging in discussions with our customers to sell the output of the ACP. We have signed long-term contracts with customers and have received accepted offers from customers for additional commitments. We will continue to meet with customers during 2009 to sell ACP output, which is critical to the success of the project. Sales contracts for this initial output represent a strategic commitment by customers to ensure a reliable, U.S.-based source of nuclear fuel that will be available for decades to come.
     Lead Cascade Test Program
     We have been conducting a Lead Cascade integrated testing program at our Piketon plant since August 2007. The test program involves the integrated testing of multiple prototype machines in a cascade configuration, and has demonstrated the ability to generate product assays in a range useable by commercial nuclear power plants. Through the Lead Cascade test program, we obtain data on machine-to-machine interactions, verify cascade performance models under a variety of operating conditions, and obtain operating experience for our plant operators and technicians. The centrifuge machines involved in the Lead Cascade integrated testing program have operated for more than 150,000 total machine hours, providing data on equipment reliability and identifying opportunities to further optimize the machine and cascade design. These prototype machines confirmed design and performance targets while verifying the predictions of our analytical performance models. We have tested the centrifuge machines in a wide range of operating conditions unlikely to be seen in normal plant operations. Lead Cascade operations also give our employees experience in operating a cascade of machines in a variety of conditions, which allow us to refine operating and maintenance procedures.
     Although the Lead Cascade test program has involved prototype machines, improved AC100 components and design features are being tested in special test stands in Oak Ridge, Tennessee and have been incrementally introduced during the current Lead Cascade operations. The next step is deploying a cascade of AC100 series machines, as discussed below.
     Initial AC100 Series Cascade
     The initial design for the AC100 machine reflects improvements learned during individual machine testing and subsequent integrated testing of the prototype machine in a cascade. During 2008, the initial AC100 machine design was released to our strategic suppliers in preparation for installing a test cascade of AC100 series machines in Piketon in 2009. The strategic suppliers have been manufacturing parts for the initial AC100 machines and the first components to build these machines were delivered in November 2008. In manufacturing parts for the AC100, suppliers must replicate on a commercial basis manufacturing that we previously self-performed in building our prototype machines. Start-up issues have arisen in this transfer of technology to our suppliers that have delayed our timetable for operation of the initial AC100 cascade. We expected to encounter start-up issues and the resolution of these issues at the outset will help to facilitate our transition to high volume manufacturing. Delays in our operation of the AC100 cascade could affect our overall deployment schedule but in light of our slow down of spending in 2009, which is impacting our schedule, this may not have any additional impact.
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     A five-stage cascade of AC100 machines is now expected to be operational early in the third quarter of 2009. This cascade will be in a commercial plant configuration and operate under commercial plant conditions. Additional machines will be added to the cascade until we reach a cascade of 40 to 50 machines, which is expected late in the third quarter of 2009. This cascade of 40 to 50 machines would operate for the rest of 2009. Although this cascade will operate in a closed-loop configuration, the flow of uranium feed and tails between individual machines in the cascade will be similar to those expected in commercial plant operations. This cascade is intended to provide additional data on equipment operation and reliability that could identify opportunities to further optimize the centrifuge and cascade design. These initial AC100 machines are expected to be integrated into a commercial cascade or used for spares.
     We expect that the first machines in the initial AC100 series cascade will have a throughput somewhat less than 350 SWU per year as we continue to optimize the AC100 series machine. For the same reason, the machines deployed in the first commercial cascade of the ACP may not achieve 350 SWU per year. However, we continue to be confident that the AC100 series machines that are deployed in the commercial plant will achieve an average performance level of 350 SWU per year, supporting an annual SWU production capacity of the ACP of 3.8 million SWU. In addition, our testing program in Oak Ridge has demonstrated the potential for machine productivity beyond 350 SWU per year. We may be able to assemble and install machines with greater SWU capacity at one or more specific planned points as we build out the ACP, which would provide us with an opportunity to increase its annual SWU production capacity beyond 3.8 million SWU. However, as discussed below in “—Capital Requirements,” our ability to achieve the 3.8 million SWU production capacity may be delayed or limited by capital constraints and potential project cost increases.
     We believe an extensive Lead Cascade test program prior to beginning to manufacture thousands of commercial plant centrifuges enables us to:
 	•	 	Verify machine performance and identify modifications to improve performance, improve machine reliability or reduce costs;	
 	 	 	 	
 	•	 	Complete facilities and integrated support equipment, such as balancing stands, assembly stands and gas test stands, needed to meet production levels of several hundred machines per month;	
 	 	 	 	
 	•	 	Train staff and supplier personnel on best practices for manufacturing, quality control, transportation, assembly, installation and testing; and	
 	 	 	 	
 	•	 	Validate manufacturing and assembly procedures.	
     Value Engineering and Continued Technology Improvements
     We anticipate releasing the design for the initial AC100 series machine in late March 2009 that will be deployed in the commercial plant. This design will reflect some value-engineering improvements from the initial AC100 design released in 2008. We plan to continue our value engineering efforts and other efforts to optimize the machine going forward. A benefit of the modular centrifuge process is the ability to deploy improved machines as they become available; therefore value-engineered aspects and other technology improvements can be integrated as the plant is built out over several years.
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     As noted previously, we expect to continue our research and development efforts during commercial deployment. New analytic capability and computer-aided manufacturing methods provide an opportunity to develop more productive and less costly machines as we seek to enhance our capability in centrifuge technology and develop a new series of machines. This will result in continued development spending that will be expensed.
     Construction of the American Centrifuge Plant
     Most of the buildings required for the commercial plant were constructed in Piketon during the 1980s by DOE. These existing structures include a centrifuge assembly building, a uranium feed and withdrawal facility, and two enrichment production buildings. We began renovating and building the ACP following receipt of a construction and operating license from the NRC in April 2007. Fluor Corporation (“Fluor”) manages the engineering, procurement and construction management activities. In September 2008, USEC and Fluor signed an amended and restated contract for services totaling approximately $1 billion through 2012. Under the new contract, Fluor will be reimbursed for costs plus a fixed base fee and an incentive fee that increases based on cost savings produced.
     Construction of the ACP includes various systems including electric, telecommunications, HVAC and water distribution. Service modules provide utilities to the centrifuge machines and the piping that enables UF 6  gas to flow throughout the enrichment production facility. Process systems will integrate and support the centrifuge machines and cascades. A distributed control system will monitor and control the enrichment processing equipment.
     The two production buildings have space for approximately 11,500 centrifuges. Contractors are preparing the floor of the production buildings for machine mounts to support the centrifuges. The feed and withdrawal facility where uranium is introduced into plant systems and low enriched uranium is withdrawn is undergoing substantial renovation. A new boiler that will provide heat to the ACP is being installed along with associated hot water piping. The first service modules, which support the operation of approximately 20 centrifuges each, will be delivered by Teledyne Brown Engineering, Inc. (“TBE”) in the first quarter of 2009.
      Machine Manufacturing and Assembly
     During the past two years, a major focus for our American Centrifuge team has been working with leading companies to create a world-class industrial infrastructure needed to build components for the highly sophisticated AC100 machines and supporting equipment. The highly specialized U.S. manufacturing base needed to build the AC100 did not exist but is being established with USEC’s leadership. In 2008, for example, we significantly refurbished a facility we purchased in Oak Ridge and installed new production machining equipment, robotics, and computer controls and testing systems to support the ramp-up to manufacturing centrifuge components. We have contracted with B&W Clinch River, LLC (“B&W”), a subsidiary of the Babcock and Wilcox Co., to manufacture upper and lower suspension assemblies, cap assemblies and column parts at this facility. B&W is also responsible for assembling and balancing rotors, and procuring or manufacturing unclassified metal parts.
     Under contract arrangements with USEC, our suppliers are also helping to create the manufacturing base for a revitalized U.S. nuclear fuel industry. A subsidiary of Alliant Techsystems Inc., or ATK, is expanding facilities it has at the Allegany Ballistics Laboratory in Rocket Center, West Virginia. It will produce the tall, carbon-fiber rotor tubes for the centrifuges. Major Tool & Machine, Inc. has built a new automated production facility at its Indianapolis, Indiana, plant to fabricate the steel casings for the machines and has delivered the first casings needed for the initial cascade of AC100 machines. TBE has significantly expanded manufacturing capacity in Huntsville, Alabama, to produce 540 gas centrifuge service modules for the ACP. These steel frame structures hold valves, cabling, ductwork and electric supply. Each service module supports up to 20 AC100 machines. Curtiss-Wright Electro-Mechanical Corporation of Cheswick, Pennsylvania, is providing the motor drives that spin the centrifuge rotor at very high speeds. Honeywell Technology Solutions is responsible for final assembly of the AC100 machines on site at the ACP.
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     Concurrent with our initial deployment of capacity for 3.8 million SWU per year, we are analyzing the nuclear fuel market and other factors to determine the economics of adding additional ACP capacity. Although we will need an amendment to our NRC license for any expansion of the ACP, the environmental impact statement issued with our license contemplated the potential impact of an expansion of the plant to approximately double its anticipated capacity. The manufacturing infrastructure that we are putting into place to deploy the initial plant capacity will facilitate any future expansion. Because an expansion would not require creating this manufacturing infrastructure or another demonstration of the technology, the cost of any expansion is anticipated to be less than the initial project.
     Project Budget
     In 2008, we established a baseline project budget of $3.5 billion following a thorough, bottom-up review of the cost to build the ACP. This budget includes amounts already spent but does not include financing costs or financial assurance related to decommissioning obligations. The expenditures to date and budget at completion follow (in millions):
 	 	 	 	 	 	 	 	 	
 	 	Cumulative	 	 	Baseline	 	
 	 	as of	 	 	Project	 	
 	 	December 31,	 	 	Budget at	 	
 	 	2008	 	 	Completion	 	
Machine technology, lead cascade and program management	 	$	361.2	 	 	$	464.2	 	
Machine manufacturing and assembly	 	 	389.7	 	 	 	1,592.5	 	
Commercial plant	 	 	422.2	 	 	 	1,442.1	 	
 	 	 	 	 	 	 	
Project development, deployment and construction	 	$	1,173.1	 	 	$	3,498.8	 	

Other costs:	 	 	 	 	 	 	 	 	
Capitalized interest	 	 	25.0	 	 	 	 	 	
Capitalized asset retirement obligations	 	 	13.0	 	 	 	 	 	

Total ACP expenditures, including accruals	 	$	1,211.1	 	 	 	 	 	

Amount expensed as part of advanced technology costs	 	$	542.1	 	 	 	 	 	
Amount capitalized as part of construction work in progress	 	$	601.8	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Equipment, building and land used for manufacturing and plant	 	$	47.0	 	 	 	 	 	
Depreciation and transfers	 	$	(4.5	)	 	 	 	 	
Prepayments to suppliers for services not yet performed	 	$	24.7	 	 	 	 	 	
     While our project budget includes some degree of embedded contingency with respect to cost assumptions for labor and materials such as carbon steel and stainless steel, we remain subject to cost escalation risk. We are working with our strategic suppliers primarily under cost-reimbursement agreements. As we proceed with the project, we intend for contracts with suppliers to transition from a cost-reimbursable model to a fixed-price or incentive-based model, as appropriate. However, if we are not successful in obtaining fixed-price or incentive-based contracts in the timeframe we expect, this could increase costs. We are also currently in discussions with our suppliers regarding a slow down of spending during 2009 from what was planned under our baseline schedule, which will likely increase the project cost as discussed below in “— Capital Requirements”.
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     Several key budget variables such as labor costs, the cost of raw materials to build the plant and general inflation, are outside our control and difficult to forecast and increases in these variables could increase costs. Our project budget assumes that certain cost savings are achieved through value-engineering the AC100 machine. If we are not successful or these efforts take longer than we expect, that could impact our schedule and/or increase costs.
     If actual costs exceed the budget (including the built-in management reserve), and such costs cannot otherwise be offset or financed, we may elect to deploy fewer centrifuge machines in the plant to mitigate such potential cost growth. The modular nature of the plant construction permits normal operation even if the scale is reduced from the current planned size. A reduced scale would reduce the output of the plant absent offsetting improvements in machine performance.
     Capital Requirements
     We must still raise the remainder of the capital needed to build the ACP, and this has been and will continue to be a focus of management. We do not believe public market financing for a large capital project such as the ACP is available to us given current financial market conditions. We view the DOE Loan Guarantee Program as the path for obtaining the debt financing to complete the American Centrifuge project.
     The DOE Loan Guarantee Program was created by the Energy Policy Act of 2005 and in December 2007, federal legislation authorized funding levels available through September 30, 2009 of up to $2 billion for advanced facilities for the front end of the nuclear fuel cycle, which includes uranium enrichment. DOE released its solicitation for the Loan Guarantee Program on June 30, 2008, and we applied for $2 billion in funding in July 2008. Areva, a company majority owned by the French government, also applied for funding under this program for a proposed plant in the U.S. and is also being considered by DOE. Nonetheless, we believe that our project is ideally suited for the Loan Guarantee Program and are seeking a selection of our project by DOE in the short term, followed by an expeditious funding commitment and financial closing.
     However, we have no assurance that our project will be selected to move forward in the program, and if we are selected, it could still take an extended period for the loan guarantee and funding to be finalized. Accordingly, we have initiated steps to conserve cash and reduce the planned escalation of project construction and machine manufacturing activities until we gain greater clarity on potential funding for the project through the DOE Loan Guarantee Program. In addition, on a parallel path, we continue to evaluate potential third-party investment.
     Our intent is to reduce our spending in 2009 to work within the combination of our expected funds available through our cash from operations and available borrowings under our credit facility and ensure that we have adequate liquidity for our ongoing operations. Under our deployment schedule for the ACP, spending was expected to peak in 2009 with spending of approximately $800 million, including a substantial ramp up in coming months with the hiring of plant construction workers and preparing facilities that would provide key components for the AC100 centrifuge machines. Our initial steps to slow the growth of project spending in 2009 include sharply reducing the planned ramp up in hiring construction and craft workers for the ACP and deferring select procurements. Engineering, procurement and construction (“EPC”) and machine manufacturing and assembly (“MM&A”) activities represent approximately 75% of planned spending in 2009 and we are targeting spending reductions in these areas. We are working with our EPC and MM&A suppliers, such as Fluor, TBE, B&W and ATK, to identify and implement actions that can be taken to reduce costs while minimizing the impact on project cost and schedule. We do not expect to reduce planned spending during 2009 on machine technology activities such as the Lead Cascade test program and operation of the AC100 cascade, which we view as critical near-term activities. As a potentially offsetting benefit to our slow down of project activities, we will also be looking for opportunities to reduce concurrency in our schedule, which could lower the overall risk of the project. For example, concurrency would be reduced if we are able to take more time to optimize the AC100 design before we commence high volume manufacturing.
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     Our baseline schedule called for beginning commercial operations at the end of the first quarter of 2010, and reaching 1 million SWU capacity in the first quarter of 2011 and the full 3.8 million SWU capacity at the end of 2012. Our decision to slow spending until a funding decision is made by the DOE Loan Guarantee Program will likely increase the cost and extend the schedule for the project. The potential cost and schedule impact is highly uncertain at this point and we are working with our suppliers to evaluate and minimize the impact. At the same time, we are actively pursuing action by the DOE Loan Guarantee Program so that we can minimize the duration of any slow down and its effect on cost and schedule. Our ability to achieve the 3.8 million SWU production capacity may be limited by capital constraints and potential project cost increases, including as a result of our decision to slow project spending. In such circumstances, achieving the full 3.8 million SWU capacity may be delayed until additional capital from project cash flow from operations or other funding becomes available. As we gain greater clarity on potential funding through the DOE Loan Guarantee Program and plan and coordinate with our strategic suppliers, we will be better able to quantify changes to cost and schedule. We are currently engaged with suppliers in a bottom-up analysis and we do not expect to be in a position to provide an update on the potential impact on cost and schedule until after the first quarter of 2009.
     As part of this process, we are planning and coordinating with our strategic suppliers regarding various scenarios based on availability of DOE funding, which could include additional reductions in spending from those currently being considered. If we continue to lack visibility into the receipt of loan guarantee funding, we might need to more drastically reduce procurements and staff, which would be more difficult to recover from and would lead to more significant delays and increased costs. We could also determine to take other actions to ensure that we have adequate liquidity for our ongoing operations. Further details are provided in Item 1A, “Risk Factors” of this report.
     Project Milestones under the 2002 DOE-USEC Agreement
     The 2002 DOE-USEC Agreement, as amended in January 2009, provides that we will develop, demonstrate and deploy the American Centrifuge technology in accordance with 15 milestones as follows:
 	 	 	 	 	
Milestones under	 	Milestone	 	Achievement	
2002 DOE-USEC Agreement	 	Date	 	Date	
Begin refurbishment of K-1600 centrifuge testing facility in Oak Ridge, Tennessee	 	December 2002	 	December 2002	
 	 	 	 	 	
Build and begin testing a centrifuge end cap	 	January 2003	 	January 2003	
 	 	 	 	 	
Submit license application for Lead Cascade to NRC	 	April 2003	 	February 2003	
 	 	 	 	 	
NRC dockets Lead Cascade application	 	June 2003	 	March 2003	
 	 	 	 	 	
First rotor tube manufactured	 	November 2003	 	September 2003	
 	 	 	 	 	
Centrifuge testing begins	 	January 2005	 	January 2005	
 	 	 	 	 	
Submit license application for commercial plant to NRC	 	March 2005	 	August 2004	
 	 	 	 	 	
NRC dockets commercial plant application	 	May 2005	 	October 2004	
 	 	 	 	 	
Begin Lead Cascade centrifuge manufacturing	 	June 2005	 	April 2005	
 	 	 	 	 	
Begin commercial plant construction and refurbishment	 	June 2007	 	May 2007	
 	 	 	 	 	
Lead Cascade operational and generating product assay in a range usable by commercial nuclear power plants	 	October 2007	 	October 2007	
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(continued)
 	 	 	 	 	
Milestones under	 	Milestone	 	Achievement	
2002 DOE-USEC Agreement	 	Date	 	Date	
 	 	 	 	 	
Secure firm financing commitment(s) for the construction of the commercial American Centrifuge Plant with an annual capacity of approximately 3.5 million SWU per year	 	November 2009	 	 	
 	 	 	 	 	
Begin commercial American Centrifuge Plant operations	 	August 2010	 	 	
 	 	 	 	 	
Commercial American Centrifuge Plant annual capacity at 1 million SWU per year	 	November 2011	 	 	
 	 	 	 	 	
Commercial American Centrifuge Plant annual capacity of approximately 3.5 million SWU per year	 	May 2013	 	 	
     We believe our ability to meet the November 2009 financing milestone is dependent upon our obtaining a commitment for a loan guarantee from DOE, the receipt and timing of which is uncertain.
     Until we have met the November 2009 financing milestone, DOE has full remedies under the 2002 DOE-USEC Agreement. However, if a delaying event beyond our control and without our fault or negligence occurs that would affect our ability to meet a milestone, we and DOE will jointly meet to discuss in good faith possible adjustments to the milestones as appropriate to accommodate the delaying event. Once we have met the November 2009 financing milestone, DOE’s remedies under the 2002 DOE-USEC Agreement are limited to those circumstances where our gross negligence in project planning and execution is responsible for schedule delays or in the circumstance where we constructively or formally abandon the project or fail to diligently pursue the financing commitment(s).
     The 2002 DOE-USEC Agreement provides DOE with specific remedies if we fail to meet a milestone that would materially impact our ability to begin commercial operations of the American Centrifuge Plant on schedule. These remedies include terminating the 2002 DOE-USEC Agreement, revoking our access to DOE’s U.S. centrifuge technology and requiring us to transfer our rights in the American Centrifuge technology and facilities to DOE, requiring us to reimburse DOE for certain costs associated with the American Centrifuge project, and recommending that we be removed as the sole U.S. Executive Agent under the Megatons to Megawatts program.
     Corporate Structure
     In September 2008 we created four wholly owned subsidiaries to carry out future commercial activities related to the American Centrifuge project. We anticipate that these subsidiaries will own the American Centrifuge Plant and equipment, provide operations and maintenance services, manufacture centrifuge machines and conduct ongoing centrifuge research and development. This corporate structure will separate ownership and control of centrifuge technology from ownership of the enrichment plant and also establish a separate operations subsidiary. This structure will facilitate DOE loan guarantee financing and potential third-party investment, while also facilitating any future plant expansion.
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     NRC Operating License
     We have an NRC license to possess and use radioactive material at the American Centrifuge Demonstration Facility that expires in August 2011. In April 2007 the NRC issued a license to construct and operate the American Centrifuge Plant, and we began construction of the American Centrifuge Plant in May 2007. Our construction and operating license is for a term of 30 years and includes authorization to enrich uranium to a U  235  assay of up to 10%. Our license is based on a plant designed with an initial annual production capacity of 3.8 million SWU. Although we will need an amendment to our NRC license for any significant expansion of the American Centrifuge Plant, the environmental report submitted with our license application and the environmental impact statement issued by the NRC contemplated the potential expansion of the plant to approximately double the currently expected capacity.
     American Centrifuge Plant Lease
     We lease the facilities in Piketon for the American Centrifuge Plant from DOE. The process buildings that will house the cascades of centrifuges encompass more than 14 acres under roof. The lease for these facilities and other support facilities is a stand-alone amendment to our lease with DOE for the gaseous diffusion plant facilities in Piketon and in Paducah. The initial term was through June 2009, and on February 2, 2009, we renewed it for an additional term of five years through June 2014. We have the option to extend the lease term for additional five-year terms up to 2043. Thereafter, we also have the right to extend the lease for up to an additional 20 years, through 2063, if we agree to demolish the existing buildings leased to us after the lease term expires. We have the option, with DOE’s consent, to expand the leased property to meet our needs until the earlier of September 30, 2013 or the expiration or termination of the GDP lease. Rent is based on the cost of lease administration and regulatory oversight and is approximately $1.6 million per year. We may terminate the lease upon three years’ notice. DOE may terminate for default, including default under the 2002 DOE-USEC Agreement.
     Financial Assurance for Decontamination and Decommissioning
     We own all capital improvements at the American Centrifuge Plant and, unless otherwise consented to by DOE, must remove them by the conclusion of the lease term. This provision is unlike the lease of our gaseous diffusion plants where we may leave the property in an “as is” condition at termination of the lease. DOE generally only remains responsible for pre-existing conditions of the American Centrifuge leased facilities. At the conclusion of the 36-year lease period in 2043, assuming no further extensions, we are obligated to return these leased facilities to DOE in a condition that meets NRC requirements and in the same condition as the facilities were in when they were leased to us (other than due to normal wear and tear). We are required to provide financial assurance to the NRC incrementally based on facility construction and centrifuge installation. We are also required to provide financial assurance to DOE in an amount equal to our current estimate of costs to comply with lease turnover requirements, less the amount of financial assurance required of us by the NRC for decontamination and decommissioning (“D&D”). As of December 31, 2008, we have provided financial assurance to the NRC and DOE in the form of surety bonds totaling $57.7 million that supports construction progress. The surety bonds are partially collateralized with interest-earning cash deposits.
     The financial assurance requirements will increase each year commensurate with the status of facility construction and operations. As part of our license to operate the American Centrifuge Plant, we provide the NRC with a projection of the total D&D cost. The current estimate of the total D&D cost related to the NRC is $377.3 million in 2008 dollars, and the projected total incremental lease turnover cost related to DOE is estimated to be $25.5 million in 2008 dollars. Financial assurance will also be required for the disposition of depleted uranium generated from future centrifuge operations.
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      Asset Retirement Obligations
     D&D requirements for the American Centrifuge Plant create asset retirement obligations. As construction of the American Centrifuge Plant takes place, the present value of the related asset retirement obligation is recognized as a liability. An equivalent amount is recognized as part of the capitalized asset cost. The liability is accreted, or increased, over time for the time value of money. The accretion is charged to cost of sales. Upon commencement of commercial operations, the asset cost will be depreciated over the shorter of the asset life or the expected lease period.
     During each reporting period, we reassess and revise the estimate of asset retirement obligations based on construction progress, cost evaluation of future D&D expectations, and other judgmental considerations which impact the amount recorded in both construction work in progress and other long-term liabilities. Our asset retirement obligation liability balance as of December 31, 2008 was $13.7 million. Cost of sales in 2008 includes accretion of the asset retirement obligation of $0.5 million.
     DOE Technology License
     In December 2006, USEC and DOE signed an agreement licensing U.S. gas centrifuge technology to USEC for use in building new domestic uranium enrichment capacity. We will pay royalties to the U.S. government on annual revenues from sales of LEU produced in the American Centrifuge Plant. The royalty ranges from 1% to 2% of annual gross revenue from these sales. Payments are capped at $100 million over the life of the technology license.
     Risks and Uncertainties
     The successful construction and operation of the American Centrifuge Plant is dependent upon a number of factors, including the availability and timing of financing, performance of the American Centrifuge technology, overall cost and schedule, and the achievement of milestones under the 2002 DOE-USEC Agreement. Risks and uncertainties related to the American Centrifuge Plant are described in further detail in Item 1A, “Risk Factors”.
Nuclear Regulatory Commission — Regulation
     Our operations are subject to regulation by the NRC. The Paducah and Portsmouth GDPs are regulated by and are required to be recertified by the NRC every five years. In 2008, the NRC granted a renewal of the certifications for the five-year period ending December 2013. The recertification represents NRC’s determination that the plants are in compliance with NRC safety, safeguards and security regulations. The NRC also regulates our operation of the American Centrifuge Demonstration Facility and the construction of the American Centrifuge Plant.
     The NRC has the authority to issue notices of violation for violations of the Atomic Energy Act of 1954, NRC regulations, and conditions of licenses, certificates of compliance, or orders. The NRC has the authority to impose civil penalties for certain violations of its regulations. We have received notices of violation from NRC for violations of these regulations and certificate conditions. However, in each case, we took corrective action to bring the facilities into compliance with NRC regulations. We do not expect that any proposed notices of violation we have received will have a material adverse effect on our financial position or results of operations.
     Our operations require that we maintain security clearances that are overseen by the NRC and DOE in accordance with the National Industrial Security Program Operating Manual. These security clearances could be suspended or revoked if we are determined by the NRC to be subject to foreign ownership, control or influence. In addition, statute and NRC regulations prohibit the NRC from issuing any license or certificate to us if it determines that we are owned, controlled or dominated by an alien, a foreign corporation, or a foreign government.
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Environmental Compliance
     Our operations are subject to various federal, state and local requirements regulating the discharge of materials into the environment or otherwise relating to the protection of the environment. Our operations generate low-level radioactive waste that is stored on-site or is shipped off-site for disposal at commercial facilities. In addition, our operations generate hazardous waste and mixed waste (i.e., waste having both a radioactive and hazardous component), most of which is shipped off-site for treatment and disposal. Because of limited treatment and disposal capacity, some mixed waste is being temporarily stored at DOE’s permitted storage facilities at the Portsmouth GDP. We have entered into a consent decree with the State of Ohio that permits the continued storage of mixed waste at DOE’s permitted storage facilities and provides for a schedule for sending the waste to off-site treatment and disposal facilities. We previously had entered into a consent decree with the State of Kentucky, which was terminated in 2007 upon satisfaction of our obligations under the consent decree.
     Our operations generate depleted uranium that is stored at the plants. Depleted uranium is a result of the uranium enrichment process where the concentration of the U  235  isotope in depleted uranium is less than the concentration of .711% found in natural uranium. All liabilities arising out of the disposal of depleted uranium generated before July 28, 1998 are direct liabilities of DOE. The USEC Privatization Act requires DOE, upon our request, to accept for disposal the depleted uranium generated after the July 28, 1998 privatization date provided we reimburse DOE for its costs.
     The gaseous diffusion plants were operated by agencies of the U.S. government for approximately 40 years prior to July 28, 1998. As a result of such operation, there is contamination and other potential environmental liabilities associated with the plants. The Paducah GDP has been designated as a Superfund site under CERCLA, and both the Paducah and Portsmouth GDPs are undergoing investigations under the Resource Conservation and Recovery Act. Environmental liabilities associated with plant operations prior to July 28, 1998 are the responsibility of the U.S. government, except for liabilities relating to the disposal of certain identified wastes generated by USEC and stored at the plants. The USEC Privatization Act and the lease for the plants provide that DOE remains responsible for decontamination and decommissioning of the gaseous diffusion plants.
     As described above under “Business and Properties — The American Centrifuge Plant — Financial Assurance for Decommissioning”, we will be responsible for the decontamination and decommissioning of the American Centrifuge Plant.
     Reference is made to Management’s Discussion and Analysis of Financial Condition and Results of Operations and note 15 to the consolidated financial statements for information on operating costs relating to environmental compliance.
Occupational Safety and Health
     Our operations are subject to regulations of the Occupational Safety and Health Administration governing worker health and safety. We maintain a comprehensive worker safety program that establishes high standards for worker safety, directly involves our employees and monitors key performance indicators in the workplace environment.
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Competition and Foreign Trade
     The highly competitive global uranium enrichment industry has four major producers of LEU:
 	•	 	USEC,	
 	 	 	 	
 	•	 	Urenco, a consortium of companies owned or controlled by the British and Dutch governments and by two private German utilities,	
 	 	 	 	
 	•	 	a multinational consortium controlled by Areva, a company principally owned by the French government, and	
 	 	 	 	
 	•	 	the Russian government’s State Atomic Energy Corporation (“Rosatom”), which sells LEU through TENEX, a Russian government-owned entity.	
     Two of our three major competitors, Urenco and Areva, own a joint venture called the Enrichment Technology Company, which develops and manufactures centrifuge machines for both owners. There are also smaller producers of LEU in China, Japan and Brazil that primarily serve a portion of their respective domestic markets.
     Global LEU suppliers compete primarily in terms of price and secondarily on reliability of supply and customer service. We believe that customers are attracted to our reputation as a reliable long-term supplier of enriched uranium, and we intend to continue strengthening this reputation with the planned transition to the American Centrifuge Plant.
     USEC and Areva currently use the gaseous diffusion process to produce LEU and are constructing centrifuge enrichment plants to replace their gaseous diffusion production. Urenco and Rosatom already use centrifuge technology. Gaseous diffusion plants generally have higher operating costs than gas centrifuge plants due to the significant amounts of electric power required by the gaseous diffusion process.
     We estimate that the enrichment industry market is currently about 45 million SWU per year. In the past five years, we have delivered LEU containing 10 to 13 million SWU per year, of which approximately 5.5 million SWU per year was obtained by us under the Russian Contract.
     Urenco publicly stated in 2008 that its European enrichment facilities would reach an annual capacity of 11 million SWU by the end of 2008. Louisiana Energy Services (“LES”), a group controlled by Urenco, is constructing a gas centrifuge uranium enrichment plant in Lea County, New Mexico. LES operations are expected to begin in the second half of 2009. Full capacity of 3 million SWU per year is expected in 2013. In November 2008, LES announced its plans to seek a license amendment to increase its planned capacity to 5.9 million SWU by 2015. Urenco’s announced plans call for total capacity, including LES, of 18 million SWU by the end of 2015.
     Areva is constructing a centrifuge enrichment plant to replace its Georges Besse gaseous diffusion plant in France. Initial production is expected in 2009 and full capacity of 7.5 million SWU per year is expected by 2016. In addition, Areva announced in December 2008 that it submitted a license application to the NRC to build its proposed Eagle Rock centrifuge uranium enrichment plant near Idaho Falls, Idaho. Areva’s plan calls for initial production in 2014 with a targeted production rate of 3 million SWU per year reached in 2019.
     Areva and Urenco’s European centrifuge enrichment facilities, as well as their plants under construction or proposed in the U.S., use or will use centrifuge machines supplied by the Enrichment Technology Company.
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     All of our current competitors are owned or controlled, in whole or in part, by foreign governments. These competitors may make business decisions in both domestic and international markets that are influenced by political or economic policy considerations rather than exclusively by commercial considerations.
     In addition, GE Hitachi has an agreement with Silex Systems Limited, an Australian company, to license Silex’s laser enrichment technology. USEC funded research and development of the Silex technology for several years but terminated the arrangement in April 2003 to focus on the American Centrifuge technology. GE Hitachi has begun a phased development process with the goal of constructing a commercial enrichment plant in Wilmington, North Carolina with a target capacity of between 3.5 million and 6 million SWU per year. Activities are currently focused on a test loop facility to determine performance and reliability data, which could be used to make a decision on whether or not to proceed with the construction of a commercial plant.
     In addition to enrichment, LEU may be produced by downblending government stockpiles of highly enriched uranium. Governments control the timing and availability of highly enriched uranium released for this purpose, and the release of this material to the market could impact market conditions. We have been the primary supplier of downblended highly enriched uranium made available by the U.S. and Russian governments. To the extent LEU from downblended highly enriched uranium are released into the market in future years for sale by others, these quantities would represent a source of competition. In December 2008, DOE published a plan for the multi-year disposition of its excess uranium inventories, including the downblending of 12.1 metric tons of highly enriched uranium to produce about 220 metric tons of LEU (containing roughly 1.5 million SWU), of which about 170 metric tons could be used for a general or special-purpose inventory for DOE. In the plan, DOE stated its intention to minimize any material adverse impacts on the domestic uranium mining, conversion and enrichment industries.
     LEU that we supply to foreign customers is exported under the terms of international agreements governing nuclear cooperation between the United States and the country of destination or other entities. For example, exports to countries comprising the European Union take place within the framework of an agreement for cooperation (the “EURATOM Agreement”) between the United States and the European Atomic Energy Community, which, among other things, permits LEU to be exported from the United States to the European Union for as long as the EURATOM Agreement is in effect.
     Government Investigation of LEU Imports from France
     In 2001, the U.S. Department of Commerce (“DOC”) determined that French enricher Eurodif, S.A., a consortium controlled by Areva, had dumped LEU into the United States, and in 2002, the DOC imposed antidumping and countervailing duty (anti-subsidy) orders on imports of LEU produced in France. These orders were challenged by Eurodif and certain U.S. utilities. As a result of these challenges, the countervailing duty order was revoked in May 2007. The antidumping order remains in place.
     In 2005, the U.S. Court of Appeals for the Federal Circuit (“Federal Circuit”) concluded that imports of French LEU pursuant to enrichment services transactions were not subject to the antidumping law because such transactions involved a sale of “services” rather than a sale of merchandise. Both the U.S. government and USEC sought reversal of the Federal Circuit decision and, in February 2008, we and the Solicitor General of the United States, joined by the general counsels of the Commerce, Defense, Energy and State Departments, appealed the Federal Circuit’s decision to the U.S. Supreme Court. On January 26, 2009, the U.S. Supreme Court in a unanimous ruling overturned the Federal Circuit’s 2005 decision. This ruling gives the DOC the ability to enforce its dumping finding against all imports of French LEU, regardless of the form of contract involved.
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     In January 2007, the DOC and the U.S. International Trade Commission (“ITC”) initiated five-year “sunset reviews” of the antidumping order against French LEU to determine if the order should remain in place. The DOC determined that termination of the antidumping order would likely lead to a continuation or recurrence of dumping of French LEU, and the ITC determined that termination of the order would likely lead to a continuation or recurrence of material injury to the U.S. enrichment industry. We supported both of these outcomes.
     The DOC’s and ITC’s final results in the sunset review have been challenged before the U.S. Court of International Trade (“CIT”), as has the ITC’s original material injury determination made in 2002 and determinations made by the DOC in past annual reviews of imports under the antidumping order. The issues in these appeals are separate from the decision of the U.S. Supreme Court (see above) and therefore, the appeals of the DOC and ITC sunset review and original injury determinations before the CIT are still pending. A reversal of either the ITC’s original material injury determination or the DOC or ITC determinations in either of the sunset review proceedings could result in the revocation of the antidumping duty order at some point in the future and a reversal of the DOC determinations in past annual reviews could result in the reduction or elimination of antidumping duties. If the order is revoked or antidumping duties are significantly reduced or eliminated, the absence of any limitation on dumped French LEU could adversely affect market prices for SWU and result in lost sales by us.
     Limitations on Imports of LEU from Russia
     Imports of LEU and other uranium products produced in the Russian Federation are subject to quotas imposed under legislation enacted into law in September 2008 and under the 1992 Russian Suspension Agreement.
     The legislation enacted in September 2008 imposes annual quotas on imports of Russian LEU through 2020. From 2008-2011, the quotas only permit a small amount of LEU to be imported. The quotas increase moderately in 2012 and 2013, and then from 2014-2020 are set at an amount equal to approximately 20% of projected annual U.S. consumption of LEU. These quotas are substantially similar to the quotas established under the amendments to the Russian Suspension Agreement discussed below. However, the legislation also includes the possibility of expanded quotas of up to an additional 5% of the domestic market annually beginning in 2014 if the Russian Federation continues to downblend highly enriched uranium after the Russian Contract is complete. As with the amendment to the Russian Suspension Agreement, the legislation also permits unlimited imports of LEU for use in initial cores for any newly licensed U.S. nuclear reactor.
     Prior to being amended in 2008, the Russian Suspension Agreement precluded the export of LEU (other than LEU under the Russian Contract) from Russia to the United States for consumption in the United States. On February 1, 2008, the DOC and Rosatom signed an amendment to the Russian Suspension Agreement that permits the Russian government to sell a stockpile of LEU containing about 400,000 SWU located in the United States, and establishes annual export quotas for the sale of Russian uranium products to U.S. utilities starting in 2011. In 2021, the suspended investigation (and the Russian Suspension Agreement) will be terminated and the export quotas will no longer apply. The September 2008 legislation provides that it supersedes the Russian Suspension Agreement in cases where they conflict.
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Employees
     A summary of our employees by location follows:
 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	No. of Employees	
 	 	 	 	at December 31,	
Location	 	2008	 	2007	
Paducah GDP	 	Paducah, KY	 	 	1,172	 	 	 	1,169	 	
Portsmouth GDP	 	Piketon, OH	 	 	1,156	 	 	 	1,147	 	
American Centrifuge	 	Primarily Oak Ridge, TN	 	 	 	 	 	 	 	 	
 	 	and Piketon, OH	 	 	500	 	 	 	397	 	
NAC	 	Primarily Norcross, GA	 	 	62	 	 	 	63	 	
Headquarters	 	Bethesda, MD	 	 	88	 	 	 	90	 	
 	 	 	 	 	 	 	 	 	 	 	
 	 	Total Employees	 	 	2,978	 	 	 	2,866	 	
     The United Steelworkers (“USW”) and the Security, Police, Fire Professionals of America (“SPFPA”) represented 54% of the employees at the GDPs at December 31, 2008. The number of employees represented and the term of each contract follows:
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Contract	 	
 	 	Number of Employees	 	 	Term	 	
Paducah GDP:	 	 	 	 	 	 	 	 	
USW Local 5-550	 	 	567	 	 	July 2011	
SPFPA Local 111	 	 	76	 	 	March 2012	
 	 	 	 	 	 	 	 	 	
Portsmouth GDP:	 	 	 	 	 	 	 	 	
USW Local 5-689	 	 	517	 	 	May 2010	
SPFPA Local 66.	 	 	99	 	 	August 2012	
     In January 2008, we entered into an agreement with the USW and USW Local 5-689 resolving issues related to the scope of the existing collective bargaining agreement at the Portsmouth GDP and providing a path forward for labor relations at the American Centrifuge Plant. The agreement recognizes that the existing Portsmouth GDP collective bargaining agreement does not apply to the American Centrifuge Plant. The agreement provides a hiring preference for qualified USW-represented workers who apply for new jobs created by us for the American Centrifuge Plant. It also provides American Centrifuge Plant workers with an opportunity to decide on union representation through an expedited election conducted by the National Labor Relations Board. The agreement states that we will remain neutral in a union organizing campaign but will recognize the USW if a majority of eligible ACP employees elect to join the union.
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Available Information
     Our internet website is www.usec.com. We make available on our website, or upon request, without charge, access to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with, or furnished to, the Securities and Exchange Commission, pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the Securities and Exchange Commission.
     Our code of business conduct provides a brief summary of the standards of conduct that are at the foundation of our business operations. The code of business conduct states that we conduct our business in strict compliance with all applicable laws. Each employee must read the code of business conduct and sign a form stating that he or she has read, understands and agrees to comply with the code of business conduct. A copy of the code of business conduct is available on our website or upon request without charge. We will disclose on the website any amendments to, or waivers from, the code of business conduct that are required to be publicly disclosed.
     We also make available free of charge, on our website, or upon request, our Board of Directors Governance Guidelines and our Board committee charters.
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Item 1A. Risk Factors
Investors should carefully consider the risk factors below, in addition to the other information in this Annual Report on Form 10-K.
The long-term viability of our business depends on our ability to replace our current enrichment facility with the American Centrifuge Plant.
     We currently use a gaseous diffusion uranium enrichment technology at the Paducah gaseous diffusion plant (“Paducah GDP”) for approximately one-half of the LEU that we need to meet our delivery obligations to our customers and to generate uranium through underfeeding to satisfy our obligations under the Russian Contract. However, our competitors utilize or are in the process of transitioning to centrifuge uranium enrichment technology. Centrifuge technology is more efficient and operationally cost-effective than gaseous diffusion technology, which requires substantial amounts of electric power to enrich uranium. We must transition to a lower operating cost technology in order to remain competitive in the long term and one that is less dependent on volatile energy markets.
     We are focused on developing and deploying an advanced uranium enrichment centrifuge technology, which we refer to as the American Centrifuge technology, as a replacement for our gaseous diffusion technology. We are not currently pursuing any strategies to replace our gaseous diffusion operations with alternatives other than the American Centrifuge Plant (“ACP”). The construction and deployment of the ACP is a large and capital-intensive undertaking that is subject to numerous risks and uncertainties. If we are unable to successfully and timely deploy the ACP on a cost-effective basis, due to the risks and uncertainties described in this section or for any other reasons, our gross profit margins, cash flows, liquidity and results of operations would be materially and adversely affected and our business likely would not remain viable over the long term.
Delays in our deployment of the American Centrifuge technology could adversely affect the overall economics, ability to finance and the likelihood of successful deployment of the ACP.
     Our baseline deployment schedule calls for beginning commercial plant operations at the end of the first quarter of 2010, and having the full 3.8 million SWU capacity at the end of 2012. However, our recent decision to slow down project spending during 2009 in order to conserve cash will likely delay this schedule, and the delay could be significant. We have also experienced a delay in our timetable for operation of the initial AC100 cascade as part of our Lead Cascade test program as a result of start-up issues in the transfer of technology to our suppliers. This could also impact our overall schedule. We have also experienced delays in the past from a variety of factors, including the failure of certain materials to meet specifications, performance problems with, and failures of, certain centrifuge components and the time-consuming process of ensuring compliance with regulatory requirements. Our efforts to reduce the centrifuge machine cost through value engineering have been delayed due to our focus on resolving issues related to component performance that arose during Lead Cascade testing and we have continued to be unable to devote the necessary resources to value engineering based on other competing factors, which impacts cost.
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     As a result of these and other factors, including factors and circumstances similar to those that have delayed us in the past, we may be unable to meet our baseline project schedule or any revised schedule. Significant delays in our schedule could:
 	•	 	increase our costs for the project, both on an overall basis and in terms of the incremental costs we must incur to recover from delays,	
 	 	 	 	
 	•	 	cause us to fail to meet a milestone under the 2002 DOE-USEC Agreement leading DOE to exercise the remedies described in the risk factor relating to the 2002 DOE-USEC Agreement,	
 	 	 	 	
 	•	 	make it more difficult for us to attract and retain customers and adversely affect our ability to compete with other enrichment plants being built in the U.S., and	
 	 	 	 	
 	•	 	extend the time under which we are contractually or otherwise required to continue to operate our high-cost Paducah GDP.	
     Any of these outcomes could substantially reduce our revenues, gross profit margins, liquidity and cash flows and adversely affect the overall economics, ability to finance and the likelihood of successful deployment of the ACP. This would have a material adverse impact on our business and prospects because we believe the long-term viability of our business depends on the successful deployment of the ACP.
     Our baseline deployment schedule and budget for the ACP are challenging. To minimize potential schedule delays, we have made, and expect to continue to make, key decisions, including decisions to expend or commit to expend large amounts of capital and resources, before we have financing to complete the ACP and before we have received all relevant centrifuge machine performance data and confirmation of the American Centrifuge project’s costs, schedule and overall viability.
If we are not able to obtain timely action from DOE regarding a loan guarantee or an alternate capital commitment, we will need to take additional steps to implement further spending reductions with respect to the American Centrifuge project.
     We must raise capital to complete the ACP. We do not believe public market financing for a large capital project such as the ACP is available to us given current financial market conditions. We view the DOE Loan Guarantee Program as the path for obtaining the debt financing to complete the American Centrifuge project. We believe that timely action by DOE regarding a loan guarantee is critical. We have initiated steps to slow down spending on the project in 2009 and reduce the planned escalation of project construction and machine manufacturing activities until we gain greater clarity on potential funding for the project through the DOE Loan Guarantee Program. Our decision to slow spending until a funding decision is made by the DOE Loan Guarantee Program will likely increase the cost and extend the schedule for the project. We are planning and coordinating with our strategic suppliers regarding various scenarios based on availability of DOE funding, which could include additional reductions in spending from those currently being considered. If we continue to lack visibility into the receipt of loan guarantee funding, we might need to more drastically reduce procurements and staff, which would be more difficult to recover from and would lead to more significant delays and increased costs and potentially make the project uneconomic. We could also be forced to take other actions, including terminating the project. Termination of the ACP would have a material adverse impact on our business and prospects because we believe the long-term viability of our business depends on the successful deployment of the American Centrifuge Plant.
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     The Loan Guarantee Program was created by the Energy Policy Act of 2005 and in December 2007, federal legislation authorized funding levels through September 30, 2009 of up to $2 billion for advanced facilities for the front end of the nuclear fuel cycle, which includes uranium enrichment. DOE released its solicitation for the Loan Guarantee Program on June 30, 2008, and we applied for $2 billion in funding in July 2008. Our application is under review by DOE. We cannot give any assurance that we will be selected or that we will receive a DOE loan guarantee at all or in the amount or the timeframe we seek. The Loan Guarantee Program is a competitive process. Areva, a company majority owned by the French government, also has applied for funding under the program for a proposed plant in the U.S. and is being considered by DOE. This could adversely affect the timing and amount of funding awarded to us, if any. Schedule delays, cost increases, or issues that may arise with respect to the American Centrifuge technology could all adversely affect our perceived creditworthiness and likelihood of selection for a DOE loan guarantee.
     DOE has not yet issued any commitments or loan guarantees under the Loan Guarantee Program, including from an initial solicitation in August 2006 (that did not apply to nuclear projects) and has not provided a timeline for the process from solicitation to being granted a loan guarantee. The change in Administration also has added delay to the process. Funding under the program is only authorized until September 30, 2009.
     We also cannot give any assurances that if we are selected to proceed with negotiations under the Loan Guarantee Program that sufficient funds will be allocated to our project. We have requested a loan guarantee for $2 billion, which is the entire amount authorized in the solicitation for front-end nuclear facilities and Areva’s competing project also is seeking the full $2 billion.
     On a parallel path, we continue to evaluate potential third-party investment; however, we cannot assure you that we will be able to attract the capital we need to complete the American Centrifuge project in a timely manner or at all.
     Factors that could affect our ability to obtain financing or the cost of such financing include:
 	•	 	the success of our demonstration of the American Centrifuge technology and the estimated costs, efficiency, timing and return on investment of the deployment of the American Centrifuge Plant (described below),	
 	 	 	 	
 	•	 	our ability to secure long-term SWU purchase commitments from customers on satisfactory terms, including adequate prices,	
 	 	 	 	
 	•	 	our ability to get loan guarantees or other support from the U.S. government,	
 	 	 	 	
 	•	 	competition for financing or loan guarantees from another uranium enrichment project and nuclear-related projects generally,	
 	 	 	 	
 	•	 	the level of success of our current operations,	
 	 	 	 	
 	•	 	SWU prices,	
 	 	 	 	
 	•	 	USEC’s perceived competitive position and investor confidence in our industry and in us,	
 	 	 	 	
 	•	 	projected costs for the disposal of depleted uranium and the decontamination and decommissioning of the American Centrifuge Plant, and the impact of related financial assurance requirements,	
 	 	 	 	
 	•	 	additional downgrades in our credit rating,	
 	 	 	 	
 	•	 	market price and volatility of our common stock,	
 	 	 	 	
 	•	 	general economic and capital market conditions,	
 	 	 	 	
 	•	 	conditions in energy markets,	
 	 	 	 	
 	•	 	regulatory developments,	
 	 	 	 	
 	•	 	our reliance on LEU delivered to us under the Russian Contract and uncertainty regarding prices and deliveries under the Russian Contract, and	
 	 	 	 	
 	•	 	restrictive covenants in the agreements governing our revolving credit facility and in our outstanding notes and any future financing arrangements that limit our operating and financial flexibility.	
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The centrifuge machines and supporting equipment that we deploy in the American Centrifuge Plant may not meet our performance targets.
     The ACP is expected to have an annual production capacity of 3.8 million SWU, which is based on the expected performance of approximately 11,500 centrifuge machines and related equipment. The expected output for the ACP is based on assumptions regarding performance and availability of machines and related equipment and actual performance may be different than we expect. Factors that can influence performance include:
 	•	 	The success of our efforts to optimize the machine we expect to deploy in the ACP to achieve 350 SWU per year;	
 	 	 	 	
 	•	 	The performance and reliability of individual components built by our strategic suppliers;	
 	 	 	 	
 	•	 	Our ability to successfully transition the technology to build AC100 machines to our strategic suppliers; and	
 	 	 	 	
 	•	 	Differences in actual commercial plant conditions from the conditions used to generate our test data.	
     Our failure to achieve expected performance could affect the overall economics of the ACP and our ability to finance and the likelihood of successful deployment of the ACP. This could have a material adverse impact on our business and prospects.
We rely on third party suppliers for key components for our AC100 machine and the American Centrifuge Plant.
     We rely on third-party suppliers for key American Centrifuge components. The failure of any of our suppliers to provide their respective components as scheduled or at all or of the quality and the precise specifications we need could result in substantial delays in, or otherwise materially hamper, the deployment of the ACP. There are a limited number of potential suppliers for these key components and finding alternate suppliers could be difficult, time consuming and costly. In addition, because such suppliers are few and due to our dependence on them for key components, our ability to obtain favorable contractual terms with these suppliers is limited. We have entered into and expect to enter into future agreements with suppliers in which we bear certain cost, schedule and performance risk. Although we will seek to manage these risks, we cannot provide any assurance that we will be able to. This could result in cost increases and unanticipated delays. Our inability to effectively integrate these suppliers and other key third-party suppliers could also result in delays and otherwise increase our costs. Delays could also occur if we decide to search for alternate suppliers or to self-perform certain items that we previously anticipated outsourcing to third-party suppliers.
The cost of the American Centrifuge project will likely exceed the baseline project budget and increased costs and cost uncertainty could adversely affect our ability to finance and deploy the American Centrifuge Plant.
     In 2008, we established a baseline project budget for the ACP of $3.5 billion. This budget includes amounts already spent but does not include financing costs or financial assurance. Through December 31, 2008, we had spent $1.2 billion on the project, which leaves a going-forward cost of $2.3 billion to complete the ACP.
     The project budget is subject to cost risk. We are working with our strategic suppliers primarily under cost-reimbursement agreements. As we proceed with the project, we intend for contracts with suppliers to transition from a cost-reimbursable model to a fixed-price or incentive-based model, as appropriate. However, if we are not successful in obtaining fixed-price or incentive-based contracts in the timeframe we expect, this could increase costs. We are also currently in discussions with our suppliers regarding a slowdown of spending during 2009 from what was originally planned, which will likely have an impact on the project cost. We are still in the early stages of planning and coordinating with our strategic suppliers and the cost impact of any slowdown could be significantly greater than we anticipate. We could also be forced to make a decision to more significantly slow spending, which could result in more significant increased costs.
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     Several key budget variables such as labor costs, the cost of raw materials to build the plant and general inflation, are outside our control and difficult to forecast and increases in these variables could increase costs. Our project budget assumes that certain cost savings are achieved through value engineering the AC100 machine. If we are not successful or these efforts take longer than we expect, that could impact our schedule and/or increase costs.
     Increases in the cost of the ACP increase the amount of external capital we must raise and could threaten our ability to successfully finance and deploy the ACP. Our ability to achieve the 3.8 million SWU plant capacity may be limited by capital constraints and potential project cost increases, including as a result of our decision to slow project spending until a funding decision is made by the DOE Loan Guarantee Program. In such circumstances, achieving the full 3.8 million capacity may be delayed until additional capital from project cash flow from operations or other funding becomes available. This could have an adverse affect on our ability to successfully deploy the ACP.
     We cannot assure investors that costs associated with the ACP will not be materially higher than anticipated or that efforts that we take to mitigate or minimize cost increases will be successful or sufficient. Our cost estimates and budget for the ACP have been, and will continue to be, based on many assumptions that are subject to change as new information becomes available or as unexpected events occur. Regardless of our success in demonstrating the technical viability of the American Centrifuge technology, uncertainty surrounding our ability to accurately estimate costs or to limit potential cost increases could jeopardize our ability to successfully finance and deploy the ACP. Our inability to finance and deploy the ACP would have a material adverse impact on our business and prospects because we believe the long-term viability of our business depends on the successful deployment of the ACP.
We are required to meet certain milestones under the 2002 DOE-USEC Agreement and our failure to meet these milestones could cause DOE to exercise one or more remedies under the 2002 DOE-USEC Agreement.
     The 2002 DOE-USEC Agreement contains specific project milestones relating to the American Centrifuge Plant. As amended in January 2009, the following four milestones remain under the 2002 DOE-USEC Agreement:
 	•	 	November 2009 — Secure firm financing commitment(s) for the construction of the commercial American Centrifuge Plant with an annual capacity of approximately 3.5 million SWU per year (the “Financing Milestone”);	
 	 	 	 	
 	•	 	August 2010 — begin commercial American Centrifuge Plant operations;	
 	 	 	 	
 	•	 	November 2011 — commercial American Centrifuge Plant annual capacity at 1 million SWU per year; and	
 	 	 	 	
 	•	 	May 2013 — commercial American Centrifuge Plant annual capacity of approximately 3.5 million SWU per year.	
     We believe our ability to meet the Financing Milestone is dependent upon our obtaining a commitment for a loan guarantee from DOE, the receipt and timing of which is uncertain. In order to meet the Financing Milestone, we must (1) obtain debt or equity commitments by November 2009, (2) such commitments together with USEC equity contributions, based on reasonable projections acceptable to DOE, need to be sufficient to meet the estimated costs to construct the ACP with an annual capacity of approximately 3.5 million SWU per year, and (3) the commitments must, in the reasonable judgment of DOE, be likely to close and fund by May 2010 or within nine months of such commitments, whichever is earlier. Therefore, even if we are able to obtain a commitment for a loan guarantee from DOE by November 2009 or earlier, DOE could still determine that we have not met the Financing Milestone.
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     The dates of the August 2010, November 2011 and May 2013 milestones were set about five months later than our baseline deployment schedule for the American Centrifuge Plant in order to provide us with some flexibility in the case of an unanticipated delay. However, our recent decision to slow down project spending during 2009 in order to conserve cash is likely to delay this schedule. The amount of the delay is uncertain at this point and a delay of more than five months would impact our ability to meet these milestones.
     Until we have met the Financing Milestone, DOE has full remedies under the 2002 DOE-USEC Agreement if we fail to meet a milestone that would materially impact our ability to begin commercial operations of the American Centrifuge Plant on schedule. These remedies include terminating the 2002 DOE-USEC Agreement, revoking our access to DOE’s U.S. centrifuge technology that we require for the success of the American Centrifuge project and requiring us to transfer our rights in the American Centrifuge technology and facilities to DOE, and requiring us to reimburse DOE for certain costs associated with the American Centrifuge project. DOE could also recommend that we be removed as the sole U.S. Executive Agent under the Megatons to Megawatts program. Any of these actions could have a material adverse impact on our business and prospects.
     The 2002 DOE-USEC Agreement provides that if a delaying event beyond our control and without our fault or negligence occurs which would affect our ability to meet a milestone, we and DOE will jointly meet to discuss in good faith possible adjustments to the milestones as appropriate to accommodate the delaying event. However, in such circumstance we may not be able to reach an agreement regarding possible adjustments or DOE may assert that a delaying event was not beyond our control or without our fault or negligence. Uncertainty surrounding our ability to meet the milestones under the 2002 DOE-USEC Agreement could also adversely affect our ability to obtain financing for the American Centrifuge project.
Significant increases in the cost of the electric power supplied to the Paducah GDP have materially increased our overall production costs and may, in the future, increase our cost of sales to a level above the average prices we bill our customers.
     Electric power constitutes approximately 70-75% of the production cost at the Paducah GDP. We purchase most of our electric power for the Paducah GDP from the Tennessee Valley Authority (“TVA”) under a multi-year power contract with TVA that expires in May 2012. The base price of power under our power contract with TVA increases moderately each year through 2012. However, our power costs under the contract are also subject to monthly adjustments to account for changes in TVA’s fuel costs, purchased power costs, and related costs, which means that our actual power costs could be greater than we anticipate. The impact of the fuel cost adjustment has been negative for USEC, imposing an average increase over base contract prices of about 15% in 2008 and 8% in 2007. The fuel cost adjustment under the TVA contract in 2009 and beyond could be greater than we experienced in 2008, and could also be very volatile. Factors that could affect TVA’s fuel and purchased-power costs and the amount of the fuel cost adjustment include coal prices, purchased power costs and hydroelectric power generation. We also purchase additional power for delivery during the summer months at market prices, which is the time of the year when market prices tend to be the highest.
     Higher costs for power put significant pressure on our business and will continue to do so unless and until we are able to replace our existing gaseous diffusion operations with more efficient centrifuge technology. Our competitors utilize or are in the process of transitioning to centrifuge technology, which requires significantly less electric power than gaseous diffusion to enrich uranium.
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     Although we are currently signing new contracts with customers in which prices for future deliveries are adjusted, in part, on the basis of changes in a power cost index, most of our sales contracts do not include provisions that permit us to pass through increases in power prices to our customers. As a result, our profit margins and cash flows under these older sales contracts are significantly reduced by higher power costs. Additionally, profit margins under new sales contracts that we enter into may be similarly impacted to the extent the adjustments in the power cost index are not sufficient to account for increases in our power costs. Accordingly, if our power costs rise and mitigating steps are unavailable or insufficient, production at the Paducah GDP could become uneconomic, which will adversely affect the long-term viability of our business. Increases in our power costs also reduce the value to us of underfeeding, which puts further upward pressure on our production costs.
     In accordance with the TVA power contract, we provide financial assurance to support our payment obligations to TVA, including providing an irrevocable letter of credit and making weekly prepayments based on TVA’s estimate of the price and our usage of power. A significant increase in the price we pay for power could increase the amount of this financial assurance, which could adversely affect our liquidity and reduce capital resources otherwise available to fund the American Centrifuge project.
     Beginning June 1, 2010 through the expiration of the contract in May 2012, the quantity of power available to us under the contract is reduced, which means we likely will be seeking to purchase additional power, the price of which is uncertain. In addition, capacity and prices under the TVA contract are only agreed upon through May 2012 and we have not yet contracted for power for periods beyond that time. If we want to purchase power to operate the Paducah GDP beyond May 2012, we may be unable to reach an acceptable agreement and we are at risk for additional power cost increases in the future.
Deliveries of LEU under the Russian Contract account for approximately one-half of our supply mix and a significant delay or stoppage of deliveries could affect our ability to meet customer orders and could pose a significant risk to our continued operations and profitability.
     A significant delay in, or stoppage or termination of, deliveries of LEU from Russia under the Russian Contract or a failure of the LEU to meet the Russian Contract’s quality specifications, could adversely affect our ability to make deliveries to our customers. A delay, stoppage or termination could occur due to a number of factors, including logistical or technical problems with shipments, commercial or political disputes between the parties or their governments, or a failure or inability by either party to meet the terms of the Russian Contract.
     Because our annual LEU production capacity is less than our total delivery commitments to customers, an interruption of deliveries under the Russian Contract could, depending on the length of such an interruption, threaten our ability to fulfill these delivery commitments with adverse effects on our reputation, costs, results of operations, cash flows and long-term viability. Depending upon the reasons for the interruption and subject to limitations of liability and force majeure terms under our sales contracts, we could be required to compensate customers for a failure or delay in delivery.
     On February 13, 2009, we entered into an amendment to the Russian Contract to revise the pricing methodology for delivery in calendar years 2010 through 2013. Approval of both the U.S. government and the government of the Russian Federation is required for the amendment to become effective. We are also awaiting the approval of the government of the Russian Federation regarding the price for deliveries in calendar year 2009 under the Russian Contract. Failure or delay in obtaining the required government approvals could have an adverse impact on our ability to receive LEU in a timely manner in order to meet our delivery commitments.
     The appointment of a substitute or additional executive agent pursuant to the U.S. government’s compliance with the terms of the Executive Agent agreement under which USEC is designated the U.S. Executive Agent would require that all or part of the fixed quantity of LEU available each year under the Russian Contract be provided to the substitute or additional executive agent. This would not only reduce our access to LEU under the Russian Contract, but would also create a significant new competitor, which could impair our ability to meet our existing delivery commitments while reducing our ability to bid for new sales. Reduced access to LEU under the Russian Contract could also increase our costs and reduce our gross profit margins.
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We depend on a single production facility in Paducah, Kentucky, for approximately one-half of our LEU supply and significant or extended unscheduled interruptions in production could affect our ability to meet customer orders and pose a significant risk to, or could significantly limit, our continued operations and profitability.
     Our annual imports of Russian LEU under the Russian Contract account for approximately one-half of the total amount of LEU that we need to meet our delivery obligations to customers. In addition, some customers do not permit us to deliver Russian LEU to them under their contracts with us. Accordingly, our production at the Paducah GDP is needed to meet our annual delivery commitments. An interruption of production at the Paducah GDP would result in a drawdown of our inventories of LEU. Depending on the length and severity of the production interruption, we could be unable to meet our annual delivery commitments, with adverse effects on our reputation, costs, results of operations, cash flows and long-term viability. Depending upon the reasons for the interruption and subject to limitations on our liability and force majeure terms under our sales contracts, we also could be required to compensate customers for a failure or delay in delivery.
     Production interruptions at the Paducah GDP could be caused by a variety of factors, such as:
 	•	 	equipment breakdowns,	
 	 	 	 	
 	•	 	interruptions of electric power, including those interruptions permitted under the TVA power agreement, or an inability to purchase electric power at an acceptable price,	
 	 	 	 	
 	•	 	regulatory enforcement actions,	
 	 	 	 	
 	•	 	labor disruptions,	
 	 	 	 	
 	•	 	unavailability or inadequate supply of uranium feedstock,	
 	 	 	 	
 	•	 	natural or other disasters, including seismic activity in the vicinity of the Paducah GDP, which is located near the New Madrid fault line, or	
 	 	 	 	
 	•	 	accidents or other incidents.	
     The Paducah GDP is owned by the U.S. government. Our rights to the plant are defined under a lease agreement with DOE and the law that the lease agreement implements. Under the 2002 DOE-USEC Agreement, we could lose our right to extend the lease of the Paducah GDP and could be required to waive our exclusive right to lease the facility if we fail on more than one occasion within specified periods to meet certain production thresholds and fail to cure the deficiency. In addition, DOE could assume responsibility for operation of the Paducah GDP if we cease production at the Paducah GDP and fail to recommence production within time periods specified in the 2002 DOE-USEC Agreement. Without a lease to the Paducah GDP and absent access to other sources of LEU, we would be unable to meet our annual delivery commitments to customers once our available inventories were exhausted.
Our ability to retain key executives and managers is critical to the success of our business.
     The success of our business depends on our key executives, managers and other skilled personnel, some of whom were involved in the development of our American Centrifuge technology and many of whom have security clearances. We do not have employment agreements with our corporate executives or American Centrifuge project managers or other key personnel nor do we have key man life insurance policies for them. If our executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity and delays in the deployment of our American Centrifuge project, on which the viability of our business depends. Given the proprietary nature of our American Centrifuge technology, we are also at risk if key American Centrifuge employees resign to work for a competitor.
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The rights of our creditors under the documents governing our indebtedness may limit our operating and financial flexibility.
     Our revolving credit facility includes various operating and financial covenants that restrict our ability, and the ability of our subsidiaries, to, among other things, incur or prepay other indebtedness, grant liens, sell assets, make investments and acquisitions, consummate certain mergers and other fundamental changes, make certain capital expenditures and declare or pay dividends or other distributions. Complying with these covenants may make it more difficult for us to successfully execute our business strategy. For example, these covenants could limit our use of the credit facility for capital expenditures related to the American Centrifuge Plant. The revolving credit agreement also requires that we maintain a minimum level of available borrowings and contains reserve provisions that may reduce the available borrowings under the credit facility periodically.
     Our failure to comply with obligations under the revolving credit facility or other agreements such as the indenture governing our outstanding convertible notes, surety bonds, and the 2002 DOE-USEC Agreement, or the occurrence of a “fundamental change” as defined in the indenture governing our outstanding convertible notes or the occurrence of a “material adverse effect” as defined in our credit facility, could result in an event of default under the credit facility. A default, if not cured or waived, could permit acceleration of our indebtedness. We cannot be certain that we will be able to remedy any default. If our indebtedness is accelerated, we cannot be certain that we will have funds available to pay the accelerated indebtedness or that we will have the ability to refinance the accelerated indebtedness on terms favorable to us or at all. In addition, our revolving credit facility matures in August 2010. We cannot be certain that we will have funds available to repay the indebtedness outstanding under the facility at that time and to replace any outstanding letters of credit under the facility or that we will have the ability to refinance the revolving credit facility on terms favorable to us or at all.
The current global financial crisis may adversely affect our liquidity, business and prospects.
     The current global financial crisis — which has included, among other things, significant reductions in available capital and liquidity from banks and other providers of credit, substantial reductions and/or fluctuations in equity values worldwide, and concerns that the worldwide economy may enter into a prolonged recessionary period — may adversely affect our liquidity, business and prospects. The global financial crisis could result in an overall decrease in demand for electricity and consequently decreased demand and increased price competition for LEU. This could adversely affect our revenues and results of operations. The global financial crisis could also affect our customers or potential customers’ access to capital, which could result in a delay or cancellation of plans to build additional reactors, and otherwise affect the growth and outlook of the nuclear industry. We could also face increased credit risk with respect to customer collections.
     The current global financial crisis could affect our ability to draw on our revolving credit facility and therefore adversely affect our liquidity. Our access to funds under our revolving credit facility is dependent on the ability of the banks that are parties to the facility to meet their funding commitments. Those banks may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from borrowers within a short period of time. The current global financial market crisis could also affect our ability to refinance our revolving credit facility when it matures in August 2010 and therefore adversely affect our liquidity.
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     The current global financial market crisis could also result in additional reductions in the fair value of our pension and postretirement benefit plan assets and higher than expected net benefit costs and additional future funding obligations, as described in note 10 to our consolidated financial statements, which could adversely affect our financial condition and results of operations.
Changes in the price for SWU or uranium could affect our gross profit margins and ability to service our indebtedness and finance the American Centrifuge project.
     Changes in the price for SWU and uranium are influenced by numerous factors, such as:
 	•	 	LEU and uranium production levels and costs in the industry,	
 	 	 	 	
 	•	 	supply and demand shifts,	
 	 	 	 	
 	•	 	actions taken by governments to regulate, protect or promote trade in nuclear material, including the continuation of existing restrictions on unfairly priced imports,	
 	 	 	 	
 	•	 	actions taken by governments to narrow, reduce or eliminate limits on trade in nuclear material, including the decrease or elimination of existing restrictions on unfairly priced imports,	
 	 	 	 	
 	•	 	actions of competitors,	
 	 	 	 	
 	•	 	exchange rates,	
 	 	 	 	
 	•	 	availability and cost of alternate fuels, and	
 	 	 	 	
 	•	 	inflation.	
     The long-term nature of our contracts with customers delays the impact of any material change in market prices and may prolong any adverse impact of low market prices on our gross profit margins. For example, even as prices increase and we secure new higher-priced contracts, we are contractually obligated to deliver LEU and uranium at lower prices under contracts signed prior to the increase. A decrease in the price for SWU could also affect our future ability to service our indebtedness and finance the American Centrifuge project.
     Additionally, an increase in the price for SWU could result in an increase in the price that we pay for the SWU component of Russian LEU. Currently, the price we are charged for the SWU component of Russian LEU under the Russian Contract is determined by a formula that employs an index of international and U.S. price points, which in turn reflects market prices. Beginning in 2010, subject to receipt of necessary governmental approvals, prices will be determined under a formula that combines a different mix of price points and other pricing elements. Under either formula, a multi-year retrospective view of market-based price points in the formula is used to minimize the disruptive effect of short-term swings in these price points. However, increases in market prices will increase the prices Russia charges us and can substantially increase our costs of sales and inventories. This increase, if not offset by increases in our sales prices, would adversely affect our cash flows and results of operations.
The release of excess government stockpiles of enriched uranium into the market could depress market prices and reduce demand for LEU from our company.
     Foreign governments have stockpiles of LEU that they could sell in the market. In addition, LEU may be produced by downblending stockpiles of highly enriched uranium owned by the U.S. and foreign governments. The release of these stockpiles into the market can depress prices and reduce demand for LEU from us, which could adversely affect our revenues, cash flows and results of operations.
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The long-term nature of our customer contracts could adversely affect our results of operations in current and future years.
     As is typically the case in our industry, we sell nearly all of our LEU under long-term contracts. The prices that we charge under many of our existing contracts (particularly those reflecting terms agreed to prior to 2006) only increase based on an agreed upon inflation index. Therefore, prices under older contracts will not increase with changes that result in increases in our actual costs, such as increased power costs or increases in the prices we pay under the Russian Contract, and do not permit us to take advantage of market increases in the price of SWU. These limitations, combined with our cost structure and our sensitivity to increased power costs due to the power-intensive gaseous diffusion technology that we currently depend on, could reduce our ability to cover our cost of sales with revenues earned under our customer contracts and could materially and adversely impact our gross profit margins and cash flows in current and future periods.
     In addition, our older contracts give customers the flexibility to determine the amounts of natural uranium that they deliver to us, which can result in our receiving less uranium from customers than we transfer from our inventory to the Russian Federation under the Russian Contract. Over time, to the extent our inventory, including uranium generated through underfeeding, is insufficient to absorb the difference, we could be required to purchase uranium to continue to meet our obligations to the Russian Federation. Depending on the market price of uranium, this could have an adverse impact on our gross profit margins, cash flows, results of operations and liquidity.
We face significant competition from three major producers who may be less cost sensitive or may be favored due to national loyalties and from emerging competitors in the domestic market.
     We compete with three major producers of LEU, all of which are wholly or substantially owned by governments: Areva (France), Rosatom/TENEX (Russia) and Urenco (Germany, Netherlands and the United Kingdom). Currently, these competitors utilize or are in the process of transitioning to more efficient and cost-effective technology to enrich uranium than we use at the Paducah GDP.
     In addition, Louisiana Energy Services, a group controlled by Urenco, is constructing a uranium enrichment plant in New Mexico, and Areva has proposed building a centrifuge uranium enrichment plant in Idaho and has applied for a loan guarantee from DOE for its plant. We also face potential competition from GE Hitachi, which has begun a phased development process with the goal of constructing a commercial enrichment plant in North Carolina using an Australian laser enrichment technology known as SILEX. All of these represent competition in our efforts to sell output from the ACP.
     Our competitors may have greater financial resources than we do, including access to below-market financing terms. Our foreign competitors enjoy support from their government owners, which may enable them to be less cost- or profit-sensitive than we are. In addition, decisions by our foreign competitors may be influenced by political and economic policy considerations rather than commercial considerations. For example, our foreign competitors may elect to increase their production or exports of LEU, even when not justified by market conditions, thereby depressing prices and reducing demand for our LEU, which could adversely affect our revenues, cash flows and results of operations. Similarly, the elimination or weakening of existing restrictions on imports from our foreign competitors could adversely affect our revenues, cash flows and results of operations.
     Imports of LEU and other uranium products produced in the Russian Federation are subject to quotas through 2020 imposed under legislation enacted into law in September 2008 and under the Russian Suspension Agreement. Although we believe these limitations will preserve a stable U.S. market, this belief may prove to be wrong, and the quantity of Russian uranium products permitted under the limitations may depress market prices and result in reduced sales by us and reduced revenues.
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Our dependence on our largest customers could adversely affect us.
     Our 10 largest utility customers represented 57% of our total revenue in 2008, and our three largest utility customers represented 30% of our total revenue in 2008. To the extent our existing contracts with these customers include prices that are greater than the prices at which we could sell to others, a reduction in purchases from these customers, whether due to their decision to increase purchases from our competitors or for other reasons, including a disruption in their operations that reduces their need for LEU from us, could adversely affect our business and results of operations. Conversely, to the extent that our contracts with these customers include prices that are lower than the prices at which we could sell to others, a decision by these customers to exercise options under these contracts to purchase more from us also could adversely affect our business and results of operations.
     We are seeking to improve the pricing under new long-term contracts with our customers as existing contracts come up for renewal. However, because price is a significant factor in a customer’s choice of a supplier of LEU, when contracts come up for renewal, customers may reduce their purchases from us if we attempt to increase our prices in order to offset increases in our costs, resulting in the loss of new sales contracts. Moreover, once lost, customers may be difficult to regain because they typically purchase LEU under long-term contracts. Therefore, given the need to maintain existing customer relationships, particularly with our largest customers, our ability to raise prices in order to respond to increases in costs or other developments may be limited. In addition, because we have a fixed commitment to order LEU derived from at least 30 metric tons of highly enriched uranium each year under the Russian Contract and to purchase the approximately 5.5 million SWU deemed to be contained in such material, any reduction in purchases from us by our customers below the level required for us to resell both our own production and the Russian material could adversely affect our revenues, cash flows and results of operations.
Our ability to compete in certain foreign markets may be limited for political, legal and economic reasons.
     Agreements for cooperation between the U.S. government and various foreign governments or governmental agencies control the export of nuclear materials from the United States. If any of the agreements governing exports to countries in which our customers are located were to lapse, terminate or be amended, it is possible we would not be able to make sales or deliver LEU to customers in those countries. This could adversely affect our results of operations.
     Purchases of LEU by customers in the European Union are subject to a policy of the Euratom Supply Agency that seeks to limit foreign enriched uranium to no more than 20% of European Union consumption per year. Further, we are precluded from selling LEU in the Russian Federation by the absence of an agreement for cooperation that permits exports to Russia.
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Our future prospects are tied directly to the nuclear energy industry worldwide.
     Potential events that could affect either nuclear reactors under contract with us or the nuclear industry as a whole, include:
 	•	 	accidents, terrorism or other incidents at nuclear facilities or involving shipments of nuclear materials,	
 	 	 	 	
 	•	 	regulatory actions or changes in regulations by nuclear regulatory bodies, or decisions by agencies, courts or other bodies that limit our ability to seek relief under applicable trade laws to offset unfair competition or pricing by foreign competitors,	
 	 	 	 	
 	•	 	disruptions in other areas of the nuclear fuel cycle, such as uranium supplies or conversion,	
 	 	 	 	
 	•	 	civic opposition to, or changes in government policies regarding, nuclear operations,	
 	 	 	 	
 	•	 	business decisions concerning reactors or reactor operations,	
 	 	 	 	
 	•	 	the need for generating capacity, or	
 	 	 	 	
 	•	 	consolidation within the electric power industry.	
     These events could adversely affect us to the extent they result in a reduction or elimination of customers’ contractual requirements to purchase from us, the suspension or reduction of nuclear reactor operations, the reduction of supplies of raw materials, lower demand, burdensome regulation, disruptions of shipments or production, increased competition from third parties, increased operational costs or difficulties or increased liability for actual or threatened property damage or personal injury.
Changes to, or termination of, any of our agreements with the U.S. government, or deterioration in our relationship with the U.S. government, could adversely affect our results of operations.
     We, or our subsidiaries, are a party to a number of agreements and arrangements with the U.S. government that are important to our business, including:
 	•	 	leases for the gaseous diffusion plants and American Centrifuge facilities,	
 	 	 	 	
 	•	 	the Executive Agent agreement under which we are designated the U.S. Executive Agent and purchase the SWU component of LEU under the Russian Contract,	
 	 	 	 	
 	•	 	the 2002 DOE-USEC Agreement and other agreements that address issues relating to the domestic uranium enrichment industry and the American Centrifuge technology,	
 	 	 	 	
 	•	 	electric power purchase agreements with the Tennessee Valley Authority,	
 	 	 	 	
 	•	 	contract work for DOE and DOE contractors at the Portsmouth and Paducah GDPs, including maintenance of the Portsmouth GDP in preparation for a DOE decontamination and decommissioning program, and	
 	 	 	 	
 	•	 	NAC consulting and transportation activities.	
     Termination or expiration of one or more of these agreements, without replacement with an equivalent agreement or arrangement that accomplishes the same objectives as the terminated or expired agreement(s), could adversely affect our results of operations. In addition, deterioration in our relationship with the U.S. agencies that are parties to these agreements could impair or impede our ability to successfully implement these agreements, which could adversely affect our results of operations.
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Our existing U.S. government contracts are subject to continued appropriations by Congress and may be terminated if future funding is not made available.
     Approximately 10% of our revenue is from U.S. government contracts. All contract work for DOE, including Portsmouth GDP maintenance and certain NAC consulting and transportation activities, is subject to the availability of DOE funding and congressional appropriations. If funds were not available, we could be required to terminate these operations and incur related termination costs. In addition, the criteria for awarding contracts to us may change such that we would not be eligible to compete for such contracts, which could adversely affect our results of operations.
     Revenue from U.S. government contract work is based on cost accounting standards and allowable costs that are subject to audit by the Defense Contract Audit Agency. Allowable costs include direct costs as well as allocations of indirect plant and corporate overhead costs. Audit adjustments could reduce the amounts we are allowed to bill for DOE contract work or require us to refund to DOE a portion of amounts already billed.
Our operations are highly regulated by the NRC and DOE.
     Our operations, including the Paducah and Portsmouth GDPs and NAC, are regulated by the NRC. In addition, the American Centrifuge Demonstration Facility and the construction and operation of the American Centrifuge Plant are licensed by the NRC, which regulates our activities at those facilities.
     Our gaseous diffusion plants are required to be recertified every five years and the term of the current certification expires on December 31, 2013. The NRC could refuse to renew either or both of the certificates if it determines that: (1) we are foreign owned, controlled or dominated; (2) the issuance of a renewed certificate would be inimical to the maintenance of a reliable and economic domestic source of enrichment; (3) the issuance of a renewed certificate would be adverse to U.S. defense or security objectives; or (4) the issuance of a renewed certificate is otherwise not consistent with applicable laws or regulations in effect at the time of renewal. The same requirements apply to NRC’s issuance of the 30-year license for the American Centrifuge Plant. If the certificate for the Paducah GDP were not renewed, we could no longer produce LEU at the Paducah GDP, which would threaten our ability to make deliveries to customers and meet the minimum production requirements under the 2002 DOE-USEC Agreement, jeopardize our cash flows, and subject us to various penalties under our customer contracts and the 2002 DOE-USEC Agreement.
     The NRC has the authority to issue notices of violation for violations of the Atomic Energy Act of 1954, NRC regulations and conditions of licenses, certificates of compliance, or orders. The NRC has the authority to impose civil penalties or additional requirements and to order cessation of operations for violations of its regulations. Penalties under NRC regulations could include substantial fines, imposition of additional requirements or withdrawal or suspension of licenses or certificates. Any penalties imposed on us could adversely affect our results of operations. The NRC also has the authority to issue new regulatory requirements or to change existing requirements. Changes to the regulatory requirements could also adversely affect our results of operations.
     Our American Centrifuge development and manufacturing facilities in Oak Ridge and certain of our operations at our other facilities are subject to regulation by DOE. DOE has the authority to impose civil penalties and additional requirements which could adversely affect our results of operations.
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     Our operations require that we maintain security clearances that are overseen by the NRC and DOE in accordance with the National Industrial Security Program Operating Manual. These security clearances could be suspended or revoked if we are determined by the NRC to be subject to foreign ownership, control or influence. In addition, statute and NRC regulations prohibit the NRC from issuing any license or certificate to us if it determines that we are owned, controlled or dominated by an alien, a foreign corporation, or a foreign government.
Our certificate of incorporation gives us certain rights with respect to equity securities held (beneficially or of record) by foreign persons. If levels of foreign ownership set forth in our certificate of incorporation are exceeded, we have the right, among other things, to redeem or exchange common stock held by foreign persons, and in certain cases, the applicable redemption price or exchange value may be equal to the lower of fair market value or a foreign person’s purchase price.
     Our certificate of incorporation gives us certain rights with respect to shares of our common stock held (beneficially or of record) by foreign persons. Foreign persons are defined in our certificate of incorporation to include, among others, an individual who is not a U.S. citizen, an entity that is organized under the laws of a non-U.S. jurisdiction and an entity that is controlled by individuals who are not U.S. citizens or by entities that are organized under the laws of non-U.S. jurisdictions.
     The occurrence of any one or more of the following events is a “foreign ownership review event” and triggers the board of directors’ right to take various actions under our certificate of incorporation: (1) the beneficial ownership by a foreign person of (a) 5% or more of the issued and outstanding shares of any class of our equity securities, (b) 5% or more in voting power of the issued and outstanding shares of all classes of our equity securities, or (c) less than 5% of the issued and outstanding shares of any class of our equity securities or less than 5% of the voting power of the issued and outstanding shares of all classes of our equity securities, if such foreign person is entitled to control the appointment and tenure of any of our management positions or any director; (2) the beneficial ownership of any shares of any class of our equity securities by or for the account of a foreign uranium enrichment provider or a foreign competitor (referred to as “contravening persons”); or (3) any ownership of, or exercise of rights with respect to, shares of any class of our equity securities or other exercise or attempt to exercise control of us that is inconsistent with, or in violation of, any regulatory restrictions, or that could jeopardize the continued operations of our facilities (an “adverse regulatory occurrence”). These rights include requesting information from holders (or proposed holders) of our securities, refusing to permit the transfer of securities by such holders, suspending or limiting voting rights of such holders, redeeming or exchanging shares of our stock owned by such holders on terms set forth in our certificate of incorporation, and taking other actions that we deem necessary or appropriate to ensure compliance with the foreign ownership restrictions.
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     The terms and conditions of our rights with respect to our redemption or exchange right in respect of shares held by foreign persons or contravening persons are as follows:
 	•	 	Redemption price or exchange value: Generally the redemption price or exchange value for any shares of our common stock redeemed or exchanged would be their fair market value. However, if we redeem or exchange shares held by foreign persons or contravening persons and our Board in good faith determines that such person knew or should have known that its ownership would constitute a foreign ownership review event (other than shares for which our Board determined at the time of the person’s purchase that the ownership of, or exercise of rights with respect to, such shares did not at such time constitute an adverse regulatory occurrence), the redemption price or exchange value is required to be the lesser of fair market value and the person’s purchase price for the shares redeemed or exchanged.	
 	 	 	 	
 	•	 	Form of payment: Cash, securities or a combination, valued by our Board in good faith.	
 	 	 	 	
 	•	 	Notice: At least 30 days’ notice of redemption is required; however, if we have deposited the cash or securities for the redemption or exchange in trust for the benefit of the relevant holders, we may redeem shares held by such holders on the same day that we provide notice.	
     Accordingly, there are situations in which a foreign stockholder or contravening person could lose the right to vote its shares or in which we may redeem or exchange shares held by a foreign person or contravening person and in which such redemption or exchange could be at the lesser of fair market value and the person’s purchase price for the shares redeemed or exchanged, which could result in a significant loss for that person.
Our operations are subject to numerous federal, state and local environmental protection laws and regulations.
     We incur substantial costs for compliance with environmental laws and regulations, including the handling, treatment and disposal of hazardous, low-level radioactive and mixed wastes generated as a result of our operations. Unanticipated events or regulatory developments, however, could cause the amount and timing of future environmental expenditures to vary substantially from those expected.
     Pursuant to numerous federal, state and local environmental laws and regulations, we are required to hold multiple permits. Some permits require periodic renewal or review of their conditions, and we cannot predict whether we will be able to renew such permits or whether material changes in permit conditions will be imposed. Changes in permits could increase costs of producing LEU and reduce our profitability. An inability to secure or renew permits could prevent us from producing LEU needed to meet our delivery obligations to customers, which would threaten our ability to make deliveries to customers and meet the minimum production requirements under the 2002 DOE-USEC Agreement, adversely affect our reputation, costs, cash flows, results of operations and long-term viability, and subject us to various penalties under our customer contracts and the 2002 DOE-USEC Agreement.
Our operations involve the use, transportation and disposal of toxic, hazardous and/or radioactive materials and could result in liability without regard to our fault or negligence.
     Our plant operations involve the use of toxic, hazardous and radioactive materials. A release of these materials could pose a health risk to humans or animals. If an accident were to occur, its severity could be significantly affected by the volume of the release and the speed of corrective action taken by plant emergency response personnel, as well as other factors beyond our control, such as weather and wind conditions. Actions taken in response to an actual or suspected release of these materials, including a precautionary evacuation, could result in significant costs for which we could be legally responsible. In addition to health risks, a release of these materials may cause damage to, or the loss of, property and may adversely affect property values.
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     We lease facilities from DOE for the Paducah and Portsmouth GDPs, the American Centrifuge Plant and centrifuge test facilities in Piketon, Ohio and Oak Ridge, Tennessee. Pursuant to the Price-Anderson Act, DOE has indemnified us against claims for public liability (as defined in the Atomic Energy Act of 1954, as amended) arising out of or in connection with activities under those leases resulting from a nuclear incident or precautionary evacuation. If an incident or evacuation is not covered under the DOE indemnification, we could be financially liable for damages arising from such incident or evacuation, which could have an adverse effect on our results of operations and financial condition. In connection with international transportation of LEU, it is possible for a claim related to a nuclear incident occurring outside the United States to be asserted that would not fall within the DOE indemnification under the Price-Anderson Act.
     While DOE has provided indemnification pursuant to the Price-Anderson Act, there could be delays in obtaining reimbursement for costs from DOE and DOE may determine that not all costs are reimbursable under the indemnification.
     We do not maintain any nuclear liability insurance for our operations at the gaseous diffusion plants. Further, American Nuclear Insurers, the only provider of nuclear liability insurance, has declined to provide nuclear liability insurance to the American Centrifuge Plant due to past and present DOE operations on the site. In addition, the Price Anderson Act indemnification does not cover loss or damage to property located on our facilities due to a nuclear incident.
     NAC’s business involves providing products and services for the storage and transportation of toxic, hazardous and radioactive materials, which, if released or mishandled, could cause personal injury and property damage (including environmental contamination) or loss and could adversely affect property values. NAC obtains nuclear liability insurance to protect against third-party liability resulting from a nuclear incident, but this insurance contains exclusions and limits and this insurance would not cover all potential liabilities.
     In our contracts, we seek to protect ourselves from liability, but there is no assurance that such contractual limitations on liability will be effective in all cases or that, in the case of NAC’s contracts, NAC’s insurance will cover all the liabilities NAC has assumed under those contracts. The costs of defending against a claim arising out of a nuclear incident or precautionary evacuation, and any damages awarded as a result of such a claim, could adversely affect our results of operations and financial condition.
The dollar amount of our sales backlog, as stated at any given time, is not necessarily indicative of our future sales revenues.
     Backlog is the aggregate dollar amount of SWU and uranium that we expect to sell in future periods under contracts with customers. As of December 31, 2008, our sales backlog was an estimated $6.9 billion, including $1.7 billion expected to be delivered during 2009. There can be no assurance that the revenues projected in our backlog will be realized, or, if realized, will result in profits. Backlog is partially based on customers’ estimates of their fuel requirements and other assumptions, including our estimates of selling prices and inflation rates. Such estimates are subject to change. For example, some of our contracts include pricing elements based on SWU or uranium market prices prevailing at the time of delivery. Pricing elements may include escalation based on a general inflation index or a power price index. We utilize external composite forecasts of future market prices and inflation rates in estimating prices that we will be entitled to charge in the future. These forecasts may not be accurate, and therefore our estimates of future prices could be overstated. Any inaccuracy in our estimates of future prices would add to the imprecision of our backlog estimate.
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     For a variety of reasons, the amounts of SWU and uranium that we will sell in the future under our existing contracts, or the timing of customer purchases under those contracts, may differ from our estimates. Customers may not purchase as much as we predicted, nor at the times we anticipated, as a result of operational difficulties, changes in fuel requirements or other reasons. Reduced purchases would reduce the revenues we actually receive from contracts included in the backlog. For example, our revenue could be reduced by actions of the NRC or nuclear regulators in foreign countries issuing orders to delay, suspend or shut down nuclear reactor operations within their jurisdictions, or by an interruption of our production of LEU or deliveries of Russian LEU to us, that we need to meet our delivery commitments to customers. Increases in our costs of production or other factors could cause sales included in our backlog to be at prices that are below our cost of sales, which could adversely affect our results of operations, and customers may purchase more under lower priced contracts than we predicted.
We use estimates in accounting for the future disposition of depleted uranium and changes in these estimates or in actual costs could affect our future financial results and liquidity.
     We currently store depleted uranium at the Paducah and Portsmouth GDPs and accrue estimated costs for its future disposition. The long-term liability for depleted uranium is dependent upon the volume of depleted uranium generated and estimated processing, transportation and disposal costs, which involves many assumptions. Our estimated cost and accrued liability are subject to change as new information becomes available, and an increase in the estimate would have an adverse effect on our results of operations.
     We anticipate that we will send most or all of our depleted uranium to DOE for disposition unless a more economic disposal option is available. DOE is constructing facilities at the Paducah and Portsmouth GDPs to process large quantities of depleted uranium owned by DOE. Under federal law, DOE would also process our depleted uranium if we provided it to DOE. If we were to dispose of our uranium in this way, we would be required to reimburse DOE for the related costs of disposal, including our pro rata share of capital costs.
     The NRC requires that we guarantee the disposition of our depleted uranium with financial assurance. Our estimate of the unit disposition cost for accrual purposes is approximately 35% less than the unit disposition cost for financial assurance purposes, which includes contingencies and other potential costs as required by the NRC. Any increase in our estimated unit cost of disposal will require us to provide additional financial assurance and could adversely affect our liquidity. The amount of future depleted uranium disposal costs could also vary substantially from amounts accrued and an increase in our actual cost of disposal could have a material adverse impact on our results of operations in future years.
     Financial assurance is also provided for the ultimate decontamination and decommissioning of the American Centrifuge facilities to meet NRC and DOE requirements. The amount of these decontamination and decommissioning costs could vary from the amounts accrued.
Deferral of revenue recognition could result in volatility in our quarterly and annual results.
     We do not recognize revenue for uranium or SWU sales in our LEU segment until LEU is physically delivered. Consequently, in sales transactions where we have received payment and title has transferred to the customer but delivery has not occurred because the terms of the agreement require us to hold uranium to which the customer has title or because a customer encounters delays in taking delivery of LEU at our facilities, recognition of revenue is deferred until LEU is physically delivered. This deferral can potentially be over an indefinite period and is outside our control and can result in volatility in our quarterly and annual results. If, in a given period, a significant amount of revenue is deferred or a significant amount of previously deferred revenue is recognized, earnings in that period will be affected, which could result in volatility in our quarterly and annual results.
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     Additional information on our deferred revenue is provided in note 8 to our consolidated financial statements.
Our operating results may fluctuate significantly from quarter to quarter, and even year to year, which could have an adverse effect on our cash flows.
     Under customer contracts with us for the supply of LEU to meet requirements for specific time periods or specific reactor refuelings, our customers order LEU from us based on their refueling schedules for nuclear reactors, which generally range from 12 to 18 months, or in some cases up to 24 months. Customer payments for the SWU component of such LEU typically average approximately $15 million per order. As a result, a relatively small change in the timing of customer orders due to a change in a customer’s refueling schedule may cause operating results to be substantially above or below expectations, which could have an adverse effect on our cash flows.
The levels of returns on pension and postretirement benefit plan assets, changes in interest rates and other factors affecting the amounts we have to contribute to fund future pension and postretirement benefit liabilities could adversely affect our earnings and cash flows in future periods.
     Our earnings may be positively or negatively impacted by the amount of expense we record for our employee benefit plans. This is particularly true with expense for our pension and postretirement benefit plans. Generally accepted accounting principles in the United States (“GAAP”) require that we calculate expense for the plans using actuarial valuations. These valuations are based on assumptions that we make relating to financial market and other economic conditions. Changes in key economic indicators can result in changes in the assumptions we use. The key year-end assumptions used to estimate pension and postretirement benefit expenses for the following year are the discount rate, the expected rate of return on plan assets, healthcare cost trend rates and the rate of increase in future compensation levels. The rate of return on our pension assets and changes in interest rates affect funding requirements for our defined benefit pension plans. The amount we contribute to our pension plans is determined by IRS regulations, the Pension Protection Act of 2006, and government cost accounting standards. For additional information and a discussion regarding how our financial statements are affected by pension and postretirement benefit plan accounting policies, see Critical Accounting Estimates in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and note 10 to our consolidated financial statements.
Anti-takeover provisions in Delaware law and in our charter, bylaws and shareholder rights plan and in the indenture governing our convertible notes could delay or prevent an acquisition of USEC.
     We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third-party to acquire control of our company, even if a change of control would be beneficial to our existing shareholders. Our certificate of incorporation, or charter, establishes restrictions on foreign ownership of our securities. Other provisions of our charter and bylaws may make it more difficult for a third-party to acquire control of us without the consent of our board of directors. We also have adopted a shareholder rights plan, which could increase the cost of, or prevent, a takeover attempt. These various restrictions could deprive shareholders of the opportunity to realize takeover premiums for their shares. Additionally, if a fundamental change occurs prior to the maturity date of our convertible notes, holders of the notes will have the right, at their option, to require us to repurchase all or a portion of their notes, and if a make-whole fundamental change occurs prior to the maturity date of our convertible notes, we will in some cases increase the conversion rate for a holder that elects to convert its notes in connection with such make-whole fundamental change. In addition, the indenture governing our convertible notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes. These and other provisions could prevent or deter a third- party from acquiring us even where the acquisition could be beneficial to you.
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Item 1B. Unresolved Staff Comments
     None.
Item 3. Legal Proceedings
     DOE Contract Services Matter
     The U.S. Department of Justice (“DOJ”) asserted in a letter to us dated July 10, 2006 that DOE may have sustained damages in an amount that exceeds $6.9 million under our contract with DOE for the supply of cold standby services at the Portsmouth GDP. DOJ indicated that it was assessing possible violations of the Civil False Claims Act (“FCA”), which allows for treble damages and civil penalties, and related claims in connection with invoices submitted under that contract. We responded to DOJ’s letter in September 2006, stating that the government does not have a legitimate basis for asserting any FCA or related claims under the cold standby contract, and have been cooperating with DOJ and the DOE Office of Investigations with respect to their inquiries into this matter. In a supplemental presentation by DOJ and DOE on October 18, 2007, DOJ identified revised assertions of alleged overcharges of at least $14.6 million on the cold standby and two other cost-type contracts, again potentially in violation of the FCA. We have responded to these assertions and have provided several follow-up responses to DOJ and DOE in response to their requests for additional data and analysis. We believe that the DOJ and DOE analyses are significantly flawed, and no loss has been accrued. We intend to defend vigorously any FCA or related claim that might be asserted against us. As part of our continuing discussions with DOJ, we and DOJ have agreed several times to extend the statute of limitations for this matter, most recently to April 10, 2009.
     Environmental Matter
     Under a cleanup agreement with the Environmental Protection Agency (“EPA”), we removed certain material from a site in South Carolina previously operated by Starmet CMI, one of our former contractors, that was attributable to quantities of depleted uranium we had sent there under a 1998 contract. In June 2007, we were contacted by the EPA concerning costs incurred by the EPA for additional cleanup at the Starmet site. In January 2009, pursuant to the terms of a September 2008 settlement agreement, we paid the EPA $1.0 million for the share of additional cleanup costs allocated to us in resolution of this matter. At this time, the EPA has completed its actions at the site and USEC is not aware of any further claims associated with the site.
     Other
     We are subject to various other legal proceedings and claims, either asserted or unasserted, which arise in the ordinary course of business. While the outcome of these claims cannot be predicted with certainty, we do not believe that the outcome of any of these legal matters will have a material adverse effect on our results of operations or financial condition.
Item 4. Submission of Matters to a Vote of Security Holders
     None.
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Executive Officers of the Company
     Executive officers are elected by and serve at the discretion of the Board of Directors. Executive officers at February 26, 2009 follow:
 	 	 	 	 	 	 	
Name	 	Age	 	Position	
John K. Welch	 	 	58	 	 	President and Chief Executive Officer	
John C. Barpoulis	 	 	44	 	 	Senior Vice President and Chief Financial Officer	
Peter B. Saba	 	 	47	 	 	Senior Vice President, General Counsel and Secretary	
Philip G. Sewell	 	 	62	 	 	Senior Vice President, American Centrifuge and Russian HEU	
Robert Van Namen	 	 	47	 	 	Senior Vice President, Uranium Enrichment	
W. Lance Wright	 	 	61	 	 	Senior Vice President, Human Resources and Administration	
John M.A. Donelson	 	 	44	 	 	Vice President, Marketing and Sales	
Stephen S. Greene	 	 	51	 	 	Vice President, Finance and Treasurer	
J. Tracy Mey	 	 	48	 	 	Controller and Chief Accounting Officer	
E. John Neumann	 	 	61	 	 	Vice President, Government Relations	
Russell B. Starkey, Jr.	 	 	66	 	 	Vice President, American Centrifuge	
Paul E. Sullivan	 	 	56	 	 	Vice President, Operations and Chief Engineer	
     John K. Welch has been President and Chief Executive Officer since September 2005. Prior to joining USEC, Mr. Welch served as a consultant to several government and corporate entities. Mr. Welch was Executive Vice President and Group Executive, Marine Systems for General Dynamics Corporation from January 2000 to March 2003, and President of General Dynamics Electric Boat from 1995 to 2000.
     John C. Barpoulis has been Senior Vice President and Chief Financial Officer since August 2006. Mr. Barpoulis joined USEC as Vice President and Treasurer in March 2005 and served as Treasurer until February 2007. Prior to joining USEC, Mr. Barpoulis was Vice President and Treasurer of National Energy & Gas Transmission, Inc. (formerly a subsidiary of PG&E Corporation) and certain of its subsidiaries from 2003 to March 2005 and was Vice President and Assistant Treasurer from 2000 to 2003.
     Peter B. Saba has been Senior Vice President, General Counsel and Secretary since February 2009 and was Vice President, General Counsel and Secretary from April 2008 to February 2009. Prior to joining USEC, Mr. Saba was of counsel in the global projects group at Paul, Hastings, Janofsky & Walker LLP from July 2005 to April 2008. Mr. Saba also served at the Export-Import Bank of the United States as chief operating officer from March 2003 to June 2005 and as senior vice president for legal affairs and general counsel from June 2001 to June 2005. Prior to that, he was counsel in the energy and project finance group at Skadden, Arps, Slate, Meagher & Flom from March 1993 to June 2001 and served in various capacities at the U.S. Department of Energy from March 1989 to January 1993, including as principal deputy assistant secretary in the Office of Domestic and International Energy Policy.
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     Philip G. Sewell has been Senior Vice President, American Centrifuge and Russian HEU since September 2005. Mr. Sewell was Senior Vice President directing international activities and corporate development programs from August 2000 to September 2005 and assumed responsibility for the American Centrifuge program in April 2005. Prior to that, Mr. Sewell was Vice President, Corporate Development and International Trade from April 1998 to April 2000, and was Vice President, Corporate Development from 1993 to April 1998.
     Robert Van Namen has been Senior Vice President, Uranium Enrichment since September 2005. Mr. Van Namen was Senior Vice President directing marketing and sales activities from January 2004 to September 2005 and was Vice President, Marketing and Sales from January 1999 to January 2004. Prior to joining USEC, Mr. Van Namen was Manager of Nuclear Fuel for Duke Power Company.
     W. Lance Wright has been Senior Vice President, Human Resources and Administration since February 2005, and was Vice President, Human Resources and Administration from August 2003 to February 2005. Prior to joining USEC, Mr. Wright was Vice President and Principal of Boyden Global Executive Search from 2002 to 2003, and previously held director and manager positions in Human Resources at ExxonMobil Corporation from 1986 to 2002.
     John M.A. Donelson has been Vice President, Marketing and Sales since December 2005 and was previously Director, North American and European Sales from June 2004 to December 2005, Director, North American Sales from August 2000 to June 2004 and Senior Sales Executive from July 1999 to August 2000.
     Stephen S. Greene has been Vice President, Finance and Treasurer since February 2007. Prior to joining USEC, Mr. Greene was a Vice President and Executive Director of Pace Global Energy Services, an energy consulting firm, from January 2006 to January 2007. Previously, Mr. Greene was a Vice President of Progress Energy, an electric utility holding company, and prior to that a Vice President of National Energy & Gas Transmission, Inc. (formerly a subsidiary of PG&E Corporation).
     J. Tracy Mey has been Controller and Chief Accounting Officer since January 2007 and had been Controller since June 2005. Prior to joining USEC, Mr. Mey was Controller and Chief Accounting Officer of Power Services Company, a national energy company and former subsidiary of PG&E Corporation, from June 2004 to May 2005, and previously was Corporate Controller of National Energy & Gas Transmission, Inc. (formerly a subsidiary of PG&E Corporation) from 1994 to 2004.
     E. John Neumann has been Vice President, Government Relations since April 2004. Prior to joining USEC, Mr. Neumann was Vice President, Government Relations, for the Edison Electric Institute from 1995 to 2004.
     Russell B. Starkey, Jr. was named Vice President, American Centrifuge in July 2008 and was Vice President, Operations from February 2005 to July 2008, General Manager of the Paducah plant from October 2001 to February 2005, Training Manager from April 1998 to October 2001 and Senior Staff Consultant from October 1997 to April 1998. Prior to joining USEC, over a 25 year period, Mr. Starkey held a variety of senior management positions including General Manager, Robinson Nuclear Plant, Vice President, Brunswick Nuclear Plant, and Vice President, Nuclear Services at Carolina Power & Light Co. (now a subsidiary of Progress Energy).
     Paul E. Sullivan was named Vice President, Operations and Chief Engineer in February 2009. Mr. Sullivan recently retired with the rank of Vice Admiral after 34 years of service in the U.S. Navy. He most recently served as the Commander of the Naval Sea Systems Command. He previously served as Chief Engineer of the Naval Sea Systems Command and Program Manager of the  Virginia  and  Seawolf  submarine classes.
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PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
     USEC’s common stock trades on the New York Stock Exchange under the symbol “USU.” High and low sales prices per share follow:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2008	 	2007	
 	 	High	 	Low	 	High	 	Low	
First Quarter ended March 31	 	$	9.31	 	 	$	3.15	 	 	$	16.62	 	 	$	12.13	 	
Second Quarter ended June 30	 	 	7.09	 	 	 	3.76	 	 	 	25.65	 	 	 	16.14	 	
Third Quarter ended September 30	 	 	6.36	 	 	 	4.29	 	 	 	22.31	 	 	 	9.56	 	
Fourth Quarter ended December 31	 	 	5.34	 	 	 	2.58	 	 	 	10.48	 	 	 	7.81	 	
     No cash dividends were paid in 2007 or 2008, and we have no intention to pay cash dividends in the foreseeable future.
     There are 250 million shares of common stock and 25 million shares of preferred stock authorized. At January 31, 2009, there were 111,349,000 shares of common stock issued and outstanding and approximately 53,000 beneficial holders of common stock. No preferred shares have been issued.
     The following table gives information about the Company’s common stock that may be issued under the USEC Inc. 1999 Equity Incentive Plan and Employee Stock Purchase Plan as of December 31, 2008.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Number of	 	 	 	 	 	 	 	
 	 	securities to be	 	 	 	 	 	 	 	
 	 	issued upon	 	 	Weighted-average	 	 	Number of securities	 	
 	 	exercise of	 	 	exercise price of	 	 	remaining available	 	
 	 	outstanding	 	 	outstanding	 	 	for future issuance	 	
 	 	options, warrants	 	 	options, warrants	 	 	under equity	 	
Plan category	 	and rights	 	 	and rights	 	 	compensation plans	 	
Equity compensation plans approved by security holders	 	 	2,120,000	 	 	$	8.52	 	 	 	5,404,000	(1)	
Equity compensation plans not approved by security holders	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,120,000	 	 	 	 	 	 	 	5,404,000	 	

 	 	 	
(1)	 	Includes 5,193,000 shares with respect to which awards are available for issuance under the USEC Inc. 1999 Equity Incentive Plan (net of awards which terminate or are cancelled without being exercised or that are settled for cash) and 211,000 shares available for issuance under the Employee Stock Purchase Plan.	
     The Board of Directors approved a shareholder rights plan in 2001. Each shareholder of record on May 9, 2001, received preferred stock purchase rights that trade together with USEC common stock and are not exercisable. In the absence of further action by the Board, the rights generally would become exercisable and allow the holder to acquire USEC common stock at a discounted price if a person or group acquires 15% or more of the outstanding shares of USEC common stock or commences a tender or exchange offer to acquire 15% or more of the common stock of USEC. However, any rights held by the acquirer would not be exercisable. The Board of Directors may direct USEC to redeem the rights at $.01 per right at any time before the tenth day following the acquisition of 15% or more of USEC common stock.
     In 2008, we did not make any unregistered sales of equity securities.
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Matters Affecting our Foreign Stockholders
     In order to aid in our compliance with certain regulatory requirements affecting us, which are described in “Business — Nuclear Regulatory Commission — Regulation”, our certificate of incorporation gives us certain rights with respect to shares of our common stock held (beneficially or of record) by foreign persons. Foreign persons are defined in our certificate of incorporation to include, among others, an individual who is not a U.S. citizen, an entity that is organized under the laws of a non-U.S. jurisdiction and an entity that is controlled by individuals who are not U.S. citizens or by entities that are organized under the laws of non-U.S. jurisdictions.
     The occurrence of any one or more of the following events is a “foreign ownership review event” and triggers the board of directors’ right to take various actions under our certificate of incorporation: (1) the beneficial ownership by a foreign person of (a) 5% or more of the issued and outstanding shares of any class of our equity securities, (b) 5% or more in voting power of the issued and outstanding shares of all classes of our equity securities, or (c) less than 5% of the issued and outstanding shares of any class of our equity securities or less than 5% of the voting power of the issued and outstanding shares of all classes of our equity securities, if such foreign person is entitled to control the appointment and tenure of any of our management positions or any director; (2) the beneficial ownership of any shares of any class of our equity securities by or for the account of a foreign uranium enrichment provider or a foreign competitor (referred to as “contravening persons”); or (3) any ownership of, or exercise of rights with respect to, shares of any class of our equity securities or other exercise or attempt to exercise control of us that is inconsistent with, or in violation of, any regulatory restrictions, or that could jeopardize the continued operations of our facilities (an “adverse regulatory occurrence”). These rights include requesting information from holders (or proposed holders) of our securities, refusing to permit the transfer of securities by such holders, suspending or limiting voting rights of such holders, redeeming or exchanging shares of our stock owned by such holders on terms set forth in our certificate of incorporation, and taking other actions that we deem necessary or appropriate to ensure compliance with the foreign ownership restrictions.
     For additional information regarding the foreign ownership restrictions set forth in our certificate of incorporation, please refer to “Risk Factors — Our certificate of incorporation gives us certain rights with respect to equity securities held (beneficially or of record) by foreign persons. If levels of foreign ownership set forth in our certificate of incorporation are exceeded, we have the right, among other things, to redeem or exchange common stock held by foreign persons, and in certain cases, the applicable redemption price or exchange value may be equal to the lower of fair market value or a foreign person’s purchase price.”
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PERFORMANCE GRAPH
     The following graph shows a comparison of cumulative total returns for an investment in the common stock of USEC Inc., the S&P 500 Index, and a peer group of companies. USEC is the only U.S. company in the uranium enrichment industry. However, USEC has identified a peer group of companies that share similar business attributes with it. This group includes utilities with nuclear power generation capabilities, chemical processing companies, and aluminum companies. USEC supplies companies in the utility industry, and its business is similar to that of chemical processing companies. USEC shares characteristics with aluminum companies in that they are both large users of electric power. The graph reflects the investment of $100 on December 31, 2003 in the Company’s common stock, the S&P 500 Index and the peer group, and reflects the reinvestment of dividends.

 	 	December 31,	 	December 31,	 	December 31,	 	December 31,	 	December 31,	 	December 31,	
 	 	2003	 	2004	 	2005	 	2006	 	2007	 	2008	
USEC Inc.	 	$	100.00	 	 	$	122.88	 	 	$	158.45	 	 	$	168.66	 	 	$	119.32	 	 	$	59.64	 	
S&P 500 Index	 	$	100.00	 	 	$	110.88	 	 	$	116.32	 	 	$	134.69	 	 	$	142.09	 	 	$	89.63	 	
Peer Group Index1	 	$	100.00	 	 	$	114.29	 	 	$	127.10	 	 	$	149.07	 	 	$	185.53	 	 	$	123.57	 	

(1)	 	The Peer Group consists of: Air Products and Chemicals, Inc., Albemarle Corporation, Alcoa Inc., Constellation Energy Group, Inc., Dominion Resources, Inc., Duke Energy Corporation, Eastman Chemical Company, Exelon Corporation, Georgia Gulf Corporation, NL Industries, Inc., PPL Corporation, Praxair, Inc., Progress Energy, Inc., The Southern Company, and XCEL Energy Inc. In accordance with SEC requirements, the return for each issuer has been weighted according to the respective issuer’s stock market capitalization at the beginning of each year for which a return is indicated.	
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Item 6. Selected Financial Data
     Selected financial data should be read in conjunction with the consolidated financial statements and related notes and management’s discussion and analysis of financial condition and results of operations. Selected financial data have been derived from audited consolidated financial statements.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	
 	 	(millions, except per share data)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Separative work units	 	$	1,175.5	 	 	$	1,570.5	 	 	$	1,337.4	 	 	$	1,085.6	 	 	$	1,027.3	 	
Uranium	 	 	217.1	 	 	 	163.5	 	 	 	316.7	 	 	 	261.3	 	 	 	224.0	 	
U.S. government contracts and other	 	 	222.0	 	 	 	194.0	 	 	 	194.5	 	 	 	212.4	 	 	 	165.9	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenue	 	 	1,614.6	 	 	 	1,928.0	 	 	 	1,848.6	 	 	 	1,559.3	 	 	 	1,417.2	 	

Cost of sales:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Separative work units and uranium	 	 	1,202.2	 	 	 	1,473.6	 	 	 	1,349.2	 	 	 	1,148.4	 	 	 	1,071.6	 	
U.S. government contracts and other	 	 	183.6	 	 	 	166.9	 	 	 	162.5	 	 	 	181.4	 	 	 	151.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total cost of sales	 	 	1,385.8	 	 	 	1,640.5	 	 	 	1,511.7	 	 	 	1,329.8	 	 	 	1,223.1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	 	228.8	 	 	 	287.5	 	 	 	336.9	 	 	 	229.5	 	 	 	194.1	 	
Special charges	 	 	—	 	 	 	—	 	 	 	3.9	(1)	 	 	7.3	(2)	 	 	—	 	
Advanced technology costs	 	 	110.2	 	 	 	127.3	 	 	 	105.5	 	 	 	94.5	 	 	 	58.5	 	
Selling, general and administrative	 	 	54.3	 	 	 	45.3	 	 	 	48.8	 	 	 	61.9	 	 	 	64.1	 	
Other (income) expense, net	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1.0	)(3)	 	 	(1.7	)(4)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	64.3	 	 	 	114.9	 	 	 	178.7	 	 	 	66.8	 	 	 	73.2	 	
Interest expense	 	 	17.3	 	 	 	16.9	 	 	 	14.5	 	 	 	40.0	 	 	 	40.5	 	
Interest (income)	 	 	(24.7	)	 	 	(33.8	)	 	 	(6.2	)	 	 	(10.5	)	 	 	(3.9	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income before income taxes	 	 	71.7	 	 	 	131.8	 	 	 	170.4	 	 	 	37.3	 	 	 	36.6	 	
Provision for income taxes	 	 	23.0	 	 	 	35.2	 	 	 	64.2	 	 	 	15.0	 	 	 	13.1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	48.7	 	 	$	96.6	 	 	$	106.2	 	 	$	22.3	 	 	$	23.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income per share —	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	.44	 	 	$	1.04	 	 	$	1.22	 	 	$	.26	 	 	$	.28	 	
Diluted	 	$	.35	 	 	$	.94	 	 	$	1.22	 	 	$	.26	 	 	$	.28	 	
Dividends per share	 	$	—	 	 	$	—	 	 	$	—	 	 	$	.55	 	 	$	.55	 	
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 	 	December 31,	
 	 	2008	 	2007	 	2006	 	2005	 	2004	
 	 	(millions)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance Sheet Data	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	248.5	 	 	$	886.1	(5)	 	$	171.4	 	 	$	259.1	 	 	$	174.8	 	
Inventories	 	 	1,231.9	 	 	 	1,153.4	 	 	 	924.2	 	 	 	1,045.7	 	 	 	1,165.6	 	
Property, plant and equipment, net	 	 	736.1	 	 	 	292.2	 	 	 	189.9	 	 	 	171.2	 	 	 	178.0	 	
Total assets	 	 	3,055.3	 	 	 	3,087.8	 	 	 	1,861.4	 	 	 	2,080.8	 	 	 	2,003.4	 	
Current portion of long-term debt	 	 	95.7	 	 	 	—	 	 	 	—	 	 	 	288.8	 	 	 	—	 	
Long-term debt	 	 	575.0	 	 	 	725.0	(5)	 	 	150.0	 	 	 	150.0	 	 	 	475.0	 	
Other long-term liabilities	 	 	601.5	 	 	 	337.5	 	 	 	300.3	 	 	 	270.2	 	 	 	244.4	 	
Stockholders’ equity	 	 	1,162.4	 	 	 	1,309.5	(5)	 	 	986.0	 	 	 	907.6	 	 	 	918.7	 	

(1)	 	Special charges of $3.9 million in 2006 include a $2.6 million impairment of an intangible asset established in 2004 relating to the acquisition of NAC, $1.5 million related to consolidation of office space in connection with the 2005 restructuring plan, and special credits totaling $0.2 million representing changes in estimate of costs for termination benefits charged in 2005.	
 	 	 	
(2)	 	The plan to restructure headquarters and field operations resulted in special charges of $7.3 million in 2005 related to termination benefits, principally consisting of severance benefits.	
 	 	 	
(3)	 	Other income in 2005 includes $1.0 million from customs duties paid to USEC as a result of trade actions.	
 	 	 	
(4)	 	Other income in 2004 includes income of $4.4 million from customs duties paid to USEC as a result of trade actions, partly offset by an expense of $2.7 million for acquired-in-process research and development expense relating to the acquisition of NAC.	
 	 	 	
(5)	 	In September 2007, we raised net proceeds, after underwriter commissions and offering expenses, of approximately $775 million through the concurrent issuance of 23 million shares of common stock and $575 million in aggregate principal amount of convertible notes.	
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion should be read in conjunction with, and is qualified in its entirety by reference to, the consolidated financial statements and related notes appearing elsewhere in this report.
Overview
     USEC, a global energy company, is a leading supplier of low enriched uranium (“LEU”) for commercial nuclear power plants. LEU is a critical component in the production of nuclear fuel for reactors to produce electricity. We:
 	•	 	supply LEU to both domestic and international utilities for use in about 150 nuclear reactors worldwide;	
 	 	 	 	
 	•	 	are deploying what we anticipate will be the world’s most advanced uranium enrichment technology, known as the American Centrifuge;	
 	 	 	 	
 	•	 	are the exclusive executive agent for the U.S. government under a nuclear nonproliferation program with Russia, known as Megatons to Megawatts;	
 	 	 	 	
 	•	 	perform contract work for the U.S. Department of Energy (“DOE”) and its contractors at the Paducah and Portsmouth gaseous diffusion plants (“GDPs”); and	
 	 	 	 	
 	•	 	provide transportation and storage systems for spent nuclear fuel and provide nuclear and energy consulting services.	
     Low Enriched Uranium
     LEU consists of two components: separative work units (“SWU”) and uranium. SWU is a standard unit of measurement that represents the effort required to transform a given amount of natural uranium into two components: enriched uranium having a higher percentage of U 235  and depleted uranium having a lower percentage of U 235 . The SWU contained in LEU is calculated using an industry standard formula based on the physics of enrichment. The amount of enrichment deemed to be contained in LEU under this formula is commonly referred to as the SWU component and the quantity of natural uranium used in the production of LEU under this formula is referred to as its uranium component.
     We produce or acquire LEU from two principal sources. We produce LEU at the Paducah GDP in Paducah, Kentucky. Under the Megatons to Megawatts program, we acquire LEU from Russia under a contract, which we refer to as the Russian Contract, to purchase the SWU component of LEU recovered from dismantled nuclear weapons from the former Soviet Union for use as fuel in commercial nuclear power plants.
     Our View of the Business Today
     There are approximately 440 nuclear power reactors in operation today, and international agencies report that more than 100 reactors are on order or planned to be built over the next two decades. In addition, approximately 260 more power reactors have been proposed. Many of these new reactors will be built in Asia. Approximately 40 plants are currently under construction worldwide in 12 countries. In addition, many reactors in the current fleet are being upgraded to produce more electricity or utilities are seeking to have their operating lives extended through equipment improvements and regulatory permission. Driving this expansion are environmental concerns and volatility in the price of fossil fuels.
     U.S. utilities have filed 17 applications for construction and operating licenses for 26 new reactors with the U.S. Nuclear Regulatory Commission (“NRC”). The NRC has also indicated it expects license applications for 7 more reactors will be filed by 2011. Growing acceptance by the public, concerns about climate change and legislation that provided financial incentives have encouraged utilities to announce plans for new nuclear reactors in the United States. New reactors in the United States are facing cost and financing pressures and many of these U.S. utilities have applied for loan guarantees. DOE reported that it received 19 applications from U.S. utilities for loan guarantees to build 21 new reactors.
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     To fuel potential new reactors, uranium enrichment capacity will need to double by 2030, according to the World Nuclear Association. New uranium enrichment plants, including our American Centrifuge Plant and other competing projects in the United States and worldwide, are being proposed and built to meet this new demand and to replace remaining higher production cost gaseous diffusion plants. These new uranium enrichment plant projects are supported by improved fundamentals in the nuclear fuel industry, including increased market prices for SWU. Long-term SWU price indicators associated with sales for deliveries in future periods increased 11% to $159 per SWU during 2008, and increased 17% over the past two years. Looking forward, we believe market supply and demand fundamentals suggest that SWU prices should remain firm as new reactors are ordered and built in the markets we serve. Increased SWU demand, higher production costs for the remaining gaseous diffusion plants, and the need to cover capital investment for new enrichment capacity are three drivers for increased market prices for SWU. Because nuclear reactors provide base load electricity and the demand for nuclear fuel from existing nuclear reactors is inelastic, our industry is less affected than others by the global economic downturn.
     As discussed in “Business and Properties — The American Centrifuge Plant,” we have been developing and demonstrating a highly efficient uranium enrichment gas centrifuge technology that we call the American Centrifuge. We are deploying this technology in the American Centrifuge Plant (“ACP”) being built in Piketon, Ohio. During 2008, we continued our efforts with respect to the centrifuge machine, with the continued operation of a cascade of prototype machines in our Lead Cascade test program, which has now operated for more than 150,000 total machine hours.
     We refer to our production centrifuge machine design as the AC100 series centrifuge machine. The AC100 series machine is designed to produce 350 SWU per year, which output is substantially greater than our competitors’ machines. During 2008, we released an initial design for the AC100 series machine to our strategic suppliers in preparation for installing a test cascade of these AC100 series machines in Piketon in 2009. We anticipate a design release for the initial AC100 series machines in late March 2009 that will be deployed in the commercial plant. The strategic suppliers have been manufacturing parts for the initial AC100 machines and the first components to build these machines were delivered in November 2008. In manufacturing parts for the AC100, suppliers must replicate on a commercial basis manufacturing that we previously self-performed in building our prototype machines. Start-up issues have arisen in this transfer of technology to our suppliers that have delayed our timetable for operation of the initial AC100 cascade. We expected to encounter start-up issues and the resolution of these issues at the outset will help to facilitate our transition to high volume manufacturing.
     A five-stage cascade of AC100 machines is now expected to be operational early in the third quarter of 2009. This cascade will be in a commercial plant configuration and operate under commercial plant conditions. Additional machines will be added to the cascade until we reach a cascade of 40 to 50 machines, which is expected late in the third quarter of 2009. This cascade of 40 to 50 machines would operate for the rest of 2009.
     We expect that the first machines in the initial AC100 series cascade will have a throughput somewhat less than 350 SWU per year as we continue to optimize the AC100 series machine. For the same reason, the machines deployed in the first commercial cascade of the ACP may not achieve 350 SWU per year. However, we continue to be confident that the AC100 series machines that are deployed in the commercial plant will achieve an average performance level of 350 SWU per year, supporting an annual SWU production capacity of the ACP of 3.8 million SWU.
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     During 2008, we also continued our construction efforts to build the ACP and to work with leading companies to create a world-class industrial infrastructure needed to build components for the highly sophisticated AC100 machines and supporting equipment. The highly specialized U.S. manufacturing base needed to build the AC100 did not exist but is being established with our leadership. Under contract arrangements with USEC, our suppliers are also helping to create the manufacturing base for a revitalized U.S. nuclear fuel industry in a dozen states. Construction of the ACP includes various systems including electric, telecommunications, cooling and water distribution. The two existing production buildings have space for approximately 11,500 centrifuges.
     We must still raise the remainder of the capital needed to build the ACP, and we view the DOE Loan Guarantee Program as the path for obtaining the debt financing to complete the American Centrifuge project. Our baseline deployment schedule called for beginning initial commercial plant operations in 2010 and reaching an annual production capacity of the ACP of 3.8 million SWU per year at the end of 2012. However, we have initiated steps to conserve cash and reduce the planned escalation of project construction and machine manufacturing activities until we gain greater clarity on potential funding for the project through the DOE Loan Guarantee Program. In addition, on a parallel path, we continue to evaluate potential third-party investment.
     Our decision to slow spending until a decision is made by the DOE Loan Guarantee Program will likely increase costs and extend the schedule for the project. As we gain greater clarity on potential funding through the DOE Loan Guarantee Program and plan and coordinate with our strategic suppliers, we will be better able to quantify changes to cost and schedule. We are currently engaged with suppliers in a bottom-up analysis and we do not expect to be in a position to provide an update on the potential impact on cost and schedule until after the first quarter of 2009. Further details are provided in “Business and Properties — The American Centrifuge Plant”, "—Liquidity and Capital Resources” and “Item 1A—Risk Factors.”
     Our Marketing and Sales department continues to meet with customers to sell ACP output, which is important to our financing efforts for ACP. We have signed long-term contracts with customers and have received accepted offers from customers for additional commitments. Sales contracts for this initial output represent a strategic commitment by customers to ensure a reliable, U.S.-based source of nuclear fuel that will be available for decades to come.
     Even as we build our new production facility, we have substantial current operations at the gaseous diffusion plant we lease from the U.S. government in Paducah, Kentucky. Today, our supply mix involves producing half of the low enriched uranium sold at the Paducah GDP and purchasing half under contract with Russia under a highly successful, nonproliferation program known as “Megatons to Megawatts.” Over the next several years we expect to transition the source of all of our LEU supply to production from the ACP. During this transition period, we will seek to effectively manage the ramp up in ACP capacity, determine the end date for commercial production from the Paducah GDP and conclude the Megatons to Megawatts program in 2013. Our business and financial profile will reflect the combined characteristics of our sources of enrichment, particularly the gaseous diffusion and centrifuge operating environments. During this transition period, we will also be looking at the potential expansion of the ACP beyond the initial 3.8 million SWU plant, which could be done incrementally once the initial ACP construction phase is complete. The manufacturing infrastructure that we are putting into place to deploy the initial plant capacity will facilitate any future expansion. Because an expansion would not require creating this manufacturing infrastructure or another demonstration of the technology, the cost of any expansion is anticipated to be less than the initial project.
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     In 2008, we exercised our option to extend the lease with DOE for the Paducah GDP through June 2016, providing us with flexibility within our current enrichment process to help us through this critical transitional period. Although we have been operating the Paducah GDP at the highest efficiency in decades, the costs to operate the Paducah GDP have increased in the past several years because of increases in power costs. Our long-term plan for the Paducah GDP is dependent upon a number of factors, including the successful and timely startup of the ACP, the cost of electric power under our contract with the Tennessee Valley Authority (“TVA”), the availability and cost of electric power beyond the expiration of the TVA contract in May 2012, the demand for SWU and uranium, the cost to maintain the Paducah GDP, and the timing and nature of any potential tails re-enrichment program or other programs we may undertake.
     During the non-summer months of 2009, we expect to purchase 2,000 megawatts of power from TVA, making USEC one of the largest industrial consumers of electric power in the United States. We have a fixed-price contract that sets the base price for most of the power we purchase, but our costs fluctuate above or below the base contract price based on fuel and purchased power costs experienced by TVA. In 2008, this fuel cost adjustment increased our power cost over the base contract price by about 15%, which had a significant effect on our net income and cash flow from operations. The impact of current economic conditions on energy prices has reduced recent weekly power invoices and has made forward cost projections from TVA very volatile, which results in uncertainty in our financial projections. We will also face uncertainty with respect to power costs as we look to purchase supplemental power starting in June 2010 when our purchases under the TVA contract are reduced from their current level of 2,000 megawatts to 1,650 megawatts and beyond the term of the current contract with TVA that expires in May 2012.
     The manner in which Russian uranium products are introduced into the U.S. market in the next few years and after the Megatons to Megawatts program concludes in 2013 is significant to our transition and to our long-term success. Russia has a large, vertically integrated nuclear power industry with excess capacity to enrich uranium. In recent years, we have been engaged in international trade litigation to ensure that the U.S. market is protected from the dumping of unfairly priced foreign merchandise, and on January 26, 2009, the U.S. Supreme Court in a unanimous ruling overturned the decision of an appellate court that had called into question the enforceability of the application of U.S. trade laws to all imports of LEU. For more information, see “Business and Properties — Competition and Foreign Trade — Government Investigation of LEU Imports from France.”
     In addition, in September 2008, legislation was enacted that included a provision to ensure the implementation of the Megatons to Megawatts program through 2013 and imposed quotas on imports of Russian LEU through 2020 that are similar to the quotas agreed to with Russia earlier in 2008. This legislation significantly reduces the threat of injury from imports of dumped Russian LEU, but does not apply to imports from any other country. For more information, see “Business and Properties — Competition and Foreign Trade — Limitations on Imports of LEU from Russia.”
     Revenue from Sales of SWU and Uranium
     Revenue from our LEU segment is derived primarily from:
 	•	 	sales of the SWU component of LEU,	
 	 	 	 	
 	•	 	sales of both the SWU and uranium components of LEU, and	
 	 	 	 	
 	•	 	sales of uranium.	
     The majority of our customers are domestic and international utilities that operate nuclear power plants, with international sales constituting approximately 30% of revenue from our LEU segment in 2008. Our agreements with electric utilities are primarily long-term, fixed-commitment contracts under which our customers are obligated to purchase a specified quantity of SWU or uranium from us or long-term requirements contracts under which our customers are obligated to purchase a percentage of their SWU requirements from us. Under requirements contracts, a customer only makes purchases if its reactor has requirements. The timing of requirements is associated with reactor refueling outages.
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     Backlog is the aggregate dollar amount of SWU and uranium that we expect to sell in future periods under contracts with customers. At December 31, 2008, we had contracts with customers aggregating an estimated $6.9 billion, including $1.7 billion expected to be delivered in 2009, compared with $6.5 billion at December 31, 2007. Backlog is partially based on customers’ estimates of their fuel requirements and certain other assumptions including our estimates of selling prices, which are subject to change. Prices may be adjusted based on SWU or uranium market prices prevailing at the time of delivery. Pricing elements may include escalation based on a general inflation index or a power price index. We utilize external composite forecasts of future market prices and inflation rates in our pricing estimates.
     Our revenues and operating results can fluctuate significantly from quarter to quarter, and in some cases, year to year. Customer demand is affected by, among other things, reactor operations, maintenance and the timing of refueling outages. Utilities typically schedule the shutdown of their reactors for refueling to coincide with the low electricity demand periods of spring and fall. Thus, some reactors are scheduled for annual or two-year refuelings in the spring or fall, or for 18-month cycles alternating between both seasons. Customer payments for the SWU component of LEU typically average approximately $15 million per order. As a result, a relatively small change in the timing of customer orders for LEU due to a change in a customer’s refueling schedule may cause operating results to be substantially above or below expectations. Customer requirements and orders are more predictable over the longer term, and we believe our performance is best measured on an annual, or even longer, business cycle. Our revenue could be adversely affected by actions of the NRC or nuclear regulators in foreign countries issuing orders to modify, delay, suspend or shut down nuclear reactor operations within their jurisdictions.
     Our financial performance over time can be significantly affected by changes in prices for SWU. The long-term SWU price indicator, as published by TradeTech, LLC in  Nuclear Market Review , is an indication of base-year prices under new long-term enrichment contracts in our primary markets. Since our backlog includes contracts awarded to us in previous years, the average SWU price billed to customers typically lags behind the current price indicators. Following are the long-term SWU price indicator, the long-term price for UF 6 , as calculated using indicators published in  Nuclear Market Review , and the spot price indicator for UF 6 :
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	
 	 	2008	 	2007	 	2006	
Long-term SWU price indicator ($/SWU)	 	$	159.00	 	 	$	143.00	 	 	$	136.00	 	
UF6:	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term price composite ($/KgU)	 	 	195.15	 	 	 	260.47	 	 	 	192.54	 	
Spot price indicator ($/KgU)	 	 	140.00	 	 	 	241.00	 	 	 	199.00	 	
     A substantial portion of our earnings and cash flows in recent years has been derived from sales of uranium. We expect to continue to supplement our supply of uranium by underfeeding the production process at the Paducah GDP. We may also purchase uranium from suppliers in connection with specific customer contracts, as we have in the past. Underfeeding is a mode of operation that uses or feeds less uranium but requires more SWU in the enrichment process, which requires more electric power. In producing the same amount of LEU, we vary our production process to underfeed uranium based on the economics of the cost of electric power relative to the prices of uranium and enrichment. As noted in the table above, spot market prices for uranium declined in 2008 while electric power costs increased, pressuring the economics of underfeeding the enrichment process to obtain uranium for resale. Given supply and demand conditions in the spot uranium market, we see fewer opportunities for near-term spot sales. We will continue to monitor and optimize the economics of our production based on the cost of power and market conditions for SWU and uranium.
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     We supply uranium to the Russian Federation for the LEU we receive under the Russian Contract. We replenish our uranium inventory with uranium supplied by customers under our contracts for the sale of SWU and through underfeeding our production process. Our older contracts give customers the flexibility to determine the amounts of natural uranium that they deliver to us, which can result in our receiving less uranium from customers than we transfer from our inventory to the Russian Federation under the Russian Contract. Our new SWU sales contracts and certain older contracts that we have renegotiated require customers to deliver a greater amount of natural uranium to us.
     The recognition of revenue and earnings for uranium sales is deferred until LEU to which the customer has title is physically delivered rather than at the time title transfers to the customer. The timing of revenue recognition for uranium sales is uncertain.
     Our contracts with customers are denominated in U.S. dollars, and although revenue has not been directly affected by changes in the foreign exchange rate of the U.S. dollar, we may have a competitive price advantage or disadvantage obtaining new contracts in a competitive bidding process depending upon the weakness or strength of the U.S. dollar. Costs of our primary competitors are denominated in the major European currencies.
     Revenue from U.S. Government Contracts
     We perform and earn revenue from contract work for DOE and DOE contractors at the Paducah and Portsmouth GDPs, including a contract for maintenance of the Portsmouth GDP in cold shutdown. DOE and USEC have periodically extended the Portsmouth GDP cold shutdown contract, most recently through April 30, 2009. DOE has announced its intention to negotiate a sole-source extension of the cold shutdown contract through September 30, 2010. Continuation of U.S. government contracts is subject to DOE funding and Congressional appropriations. Revenue from U.S. government contracts is based on allowable costs determined under government cost accounting standards. Allowable costs include direct costs as well as allocations of indirect plant and corporate overhead costs and are subject to audit by the Defense Contract Audit Agency. Also refer to “DOE Contract Services Matter” in note 16 to the consolidated financial statements. Revenue from the U.S. government contracts segment includes revenue from our subsidiary NAC International Inc. (“NAC”).
     Cost of Sales
     Cost of sales for SWU and uranium is based on the amount of SWU and uranium sold and delivered during the period and is determined by a combination of inventory levels and costs, production costs, and purchase costs. Production costs consist principally of electric power, labor and benefits, long-term depleted uranium disposition cost estimates, materials, depreciation and amortization, and maintenance and repairs. Under the monthly moving average inventory cost method that we use, coupled with our inventories of SWU and uranium, an increase or decrease in production or purchase costs will have an effect on inventory costs and cost of sales over current and future periods.
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     We have agreed to purchase approximately 5.5 million SWU each calendar year for the remaining term of the Russian Contract through 2013. Purchases under the Russian Contract are approximately one-half of our supply mix. Prices are determined using a discount from an index of international and U.S. price points, including both long-term and spot prices. A multi-year retrospective view of the index is used to minimize the disruptive effect of short-term market price swings. Increases in these price points in recent years have resulted in increases to the index used to determine prices under the Russian Contract. On February 13, 2009, we entered into an amendment to the Russian Contract to revise the pricing methodology for delivery in calendar years 2010 through 2013. Approval of both the U.S. government and the government of the Russian Federation is required for the amendment to become effective. The new pricing methodology is intended to enhance the stability of future pricing for both parties through a formula that combines a different mix of price points and other pricing elements. We expect that prices paid under the Russian Contract, as amended, will continue to increase year over year, and that the total amount paid to the Russian Federation for the SWU component of the LEU delivered under the Russian Contract over the 20 year term of the contract will substantially exceed $8 billion by the time the contract is completed in 2013. Officials of the Russian government have announced that Russia will not extend the Russian Contract or the government-to-government agreement it implements, beyond 2013. Accordingly, we do not anticipate that we will purchase Russian SWU after 2013.
     We provide for the remainder of our supply mix from the Paducah GDP. The gaseous diffusion process uses significant amounts of electric power to enrich uranium. Costs for electric power are approximately 70-75% of production costs at the Paducah GDP. In 2008, the power load at the Paducah GDP averaged 1,680 megawatts, an increase of 11% compared to 2007. Additional purchases of power allow us to underfeed the production process and increase our LEU production. The quantity of uranium that is added to uranium inventory from underfeeding is accounted for as a byproduct of the enrichment process. Production costs are allocated to the uranium added to inventory based on the net realizable value of the uranium, and the remainder of production costs is allocated to SWU inventory costs.
     We purchase most of the electric power for the Paducah GDP under a power purchase agreement with TVA that expires May 31, 2012. Pricing under the TVA power contract consisted of a summer and a non-summer base energy price through May 31, 2008. Beginning June 1, 2008, the price consists of a year-round base energy price that increases moderately based on a fixed, annual schedule. All prices are subject to a fuel cost adjustment provision to reflect changes in TVA’s fuel costs, purchased power costs, and related costs. The impact of the fuel cost adjustment has been negative for USEC, imposing an average increase over base contract prices of about 15% in 2008 and 8% in 2007. The impact of future fuel cost adjustments, which is substantially influenced by coal prices and hydroelectric power availability, is uncertain and our cost of power could fluctuate in the future above or below the agreed increases in the base energy price. We expect the fuel cost adjustment to continue to cause our purchase cost to remain above base contract prices, but is uncertain given volatile energy prices.
     The quantity of power purchases under the TVA contract generally ranges from 300 megawatts in the summer months (June — August) to up to 2,000 megawatts in the non-summer months. We supplement the TVA contract during the summer months with additional power purchased at market-based prices. Beginning June 1, 2010 through the expiration of the contract on May 31, 2012, the quantity of non-summer power purchases will be reduced to a maximum of 1,650 megawatts at all hours. This is designed to provide a transition down for the TVA power system because of the significant amount of power being purchased by us. We expect to supplement the TVA contract with additional power purchases beginning June 1, 2010 and will be evaluating possible sources of power for delivery after May 31, 2012.
     We are required to provide financial assurance to support our payment obligations to TVA. These include a letter of credit and weekly prepayments based on TVA’s estimate of the price and our usage of power.
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     Advanced Technology Costs
     Expenditures related to American Centrifuge technology for the years ended December 31, 2008, 2007, and 2006, as well as cumulative expenditures as of December 31, 2008, follow (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Cumulative	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	as of	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	December	 	
 	 	2008	 	 	2007	 	 	2006	 	 	31, 2008	 	
Amount expensed as part of advanced technology costs	 	$	108.8	 	 	$	125.9	 	 	$	103.3	 	 	$	542.1	 	
Amount capitalized as part of construction work in progress (A)	 	 	420.0	 	 	 	118.5	 	 	 	41.2	 	 	 	601.8	 	
Equipment, building and land used for manufacturing and plant	 	 	37.0	 	 	 	6.4	 	 	 	1.1	 	 	 	47.0	 	
Depreciation and transfers (B)	 	 	(3.0	)	 	 	(0.6	)	 	 	(0.5	)	 	 	(4.5	)	
Prepayments to suppliers for services not yet performed	 	 	7.8	 	 	 	16.9	 	 	 	—	 	 	 	24.7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total ACP expenditures, including accruals (C)	 	$	570.6	 	 	$	267.1	 	 	$	145.1	 	 	$	1,211.1	 	

 	 	 	
(A)	 	Amounts capitalized include interest of $14.7 million in 2008, $6.3 million in 2007 and $3.1 million in 2006. Cumulative capitalized interest as of December 31, 2008 is $25.0 million.	
 	 	 	
(B)	 	Depreciation and transfers represents the systematic and rational allocation of the costs for equipment and building used for manufacturing and plant that are ready for their intended use. These depreciation and transfers are part of the amount capitalized as part of construction work in progress.	
 	 	 	
(C)	 	Total expenditures are all American Centrifuge costs including, but not limited to, demonstration facility, licensing activities, commercial plant facility, program management, interest related costs and accrued asset retirement obligations capitalized. This includes $48.5 million of accruals at December 31, 2008.	
     For discussions of the financing plan for the American Centrifuge Plant, see “Management’s Discussion and Analysis — Liquidity and Capital Resources.” For discussions of the project budget for the American Centrifuge Plant, see “Business and Properties — The American Centrifuge Plant — Project Budget.” Risks and uncertainties related to the deployment of the American Centrifuge Plant are described in Item 1A, “Risk Factors” of this report.
     Advanced technology costs also include research and development efforts undertaken for NAC, relating primarily to its new generation MAGNASTOR™ dual-purpose dry storage system for spent fuel. MAGNASTOR, or Modular, Advanced Generation, Nuclear All-purpose Storage System, consists of a welded stainless steel canister inside a steel-lined concrete cask for storage. On February 4, 2009, MAGNASTOR was added to the NRC’s list of dry storage casks approved for use under a general license. MAGNASTOR has the largest capacity of any cask system approved to date. NAC will submit an amendment for the storage of damaged fuel and an application for a transport license including damaged fuel in 2009.
     Critical Accounting Estimates
     Our significant accounting policies are summarized in note 1 to our consolidated financial statements, which were prepared in accordance with generally accepted accounting principles. Included within these policies are certain policies that require critical accounting estimates and judgments. Critical accounting estimates are those that require management to make assumptions about matters that are uncertain at the time the estimate is made and for which different estimates, often based on complex judgments, probabilities and assumptions that we believe to be reasonable, but are inherently uncertain and unpredictable, could have a material impact on our operating results and financial condition. It is also possible that other professionals, applying their own judgment to the same facts and circumstances, could develop and support a range of alternative estimated amounts. We are also subject to risks and uncertainties that may cause actual results to differ from estimated amounts, such as the healthcare environment, legislation and regulation.
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     The sensitivity analyses used below are not intended to provide a reader with our predictions of the variability of the estimates used. Rather, the sensitivities used are included to allow the reader to understand a general cause and effect of changes in estimates.
     We have identified the following to be our critical accounting estimates:
     Pension and Postretirement Health and Life Benefit Costs and Obligations
     We provide retirement benefits under defined benefit pension plans and postretirement health and life benefit plans. The valuation of benefit obligations and costs is based on provisions of the plans and actuarial assumptions that involve judgments and estimates. Changes in actuarial assumptions could impact the measurement of benefit obligations and benefit costs, as follows:
 	•	 	The weighted average expected return on benefit plan assets was 8.0% for 2008 and is 7.7% for 2009. The expected return is based on historical returns and expectations of future returns for the composition of the plans’ equity and debt securities. A 0.5% decrease in the expected return on plan assets would increase annual pension costs by $2.8 million and postretirement health and life costs by $0.2 million.	
 	 	 	 	
 	 	 	The differences between the actual return on plan assets and expected return on plan assets are accumulated in Net Actuarial Gains and (Losses), which are recognized as an increase or decrease to benefit costs over a number of years based on the employees’ average future service lives, provided such amounts exceed certain thresholds which are based upon the obligation or the value of plan assets, as provided by accounting standards.	
 	 	 	 	
 	 	 	In 2008, actual returns for our defined benefit pension plan assets were significantly below our expected long-term rate of return on plan assets of 8% due to adverse conditions in the financial markets. This performance and the associated decline in pension plan asset values did not impact our funding pattern with respect to these plans in 2008.	
 	 	 	 	
 	•	 	A weighted average discount rate of 6.1% was used at December 31, 2008 to calculate the net present value of benefit obligations. The discount rate is the estimated rate at which the benefit obligations could be effectively settled on the measurement date and is based on yields of high quality fixed income investments whose cash flows match the timing and amount of expected benefit payments of the plans. A 0.5% reduction in the discount rate would increase the valuation of pension benefit obligations by $50.2 million and postretirement health and life benefit obligations by $9.8 million, and the resulting changes in the valuations would increase annual pension costs by $5.6 million and postretirement health and life benefit costs by $1.1 million.	
 	 	 	 	
 	•	 	The healthcare costs trend rates are 8.25% projected in 2009 reducing to 5.0% in 2016. The healthcare costs trend rate represents our estimate of the annual rate of increase in the gross cost of providing benefits. The trend rate is a reflection of health care inflation assumptions, changes in healthcare utilization and delivery patterns, technological advances, and changes in the health status of our plan participants. A 1% increase in the healthcare cost trend rates would increase postretirement health benefit obligations by about $8.6 million and would increase costs by about $1.0 million.	
     Costs for the Future Disposition of Depleted Uranium and GDP Lease Turnover Costs
     SWU and uranium inventories include estimates and judgments for production quantities and production costs. Production costs include estimates of future expenditures for the conversion, transportation and disposition of depleted uranium, the treatment and disposal of hazardous, low-level radioactive and mixed wastes, and GDP lease turnover costs. An increase or decrease in production costs has an effect on inventory costs and cost of sales over current and future periods.
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     We store depleted uranium generated from our operations at the Paducah and Portsmouth GDPs and accrue estimated costs for its future disposition. We anticipate that we will send most or all of our depleted uranium to DOE for disposition unless a more economic disposal option becomes available. DOE is constructing facilities at the Paducah and Portsmouth GDPs to process large quantities of depleted uranium owned by DOE. Under federal law, DOE would also process our depleted uranium if we provided it to DOE for disposal. If we were to dispose of our depleted uranium in this way, we would be required to reimburse DOE for the related costs of disposing our depleted uranium, including our pro rata share of DOE’s capital costs. Processing DOE’s depleted uranium is expected to take about 25 years. The timing of the disposal of our depleted uranium has not been determined. The long-term liability for depleted uranium disposition is dependent upon the volume of depleted uranium that we generate and estimated processing, transportation and disposal costs. Our estimate of the unit disposal cost is based primarily on estimated cost data obtained from DOE without consideration given to contingencies or reserves. Our estimate of the unit cost is periodically reviewed and updated as additional information becomes available.
     The NRC requires that we guarantee the disposition of our depleted uranium with financial assurance. Our estimate of the unit disposition cost for accrual purposes is approximately 35% less than the unit disposition cost for financial assurance purposes, which includes contingencies and other potential costs as required by the NRC. Our estimated cost and accrued liability, as well as financial assurance we provide for the disposition of depleted uranium, are subject to change as additional information becomes available.
     Lease turnover costs are estimated and accrued for the Paducah and Portsmouth GDPs. For the operating Paducah GDP, the balance of expected costs is being accrued over the expected productive life of the plant. Costs of returning the GDPs to DOE in acceptable condition include removing uranium deposits as required and removing USEC-generated waste. Significant estimates and judgments relate to staffing and other costs associated with the planning, execution and documentation of the lease turnover requirements.
     The amount and timing of future costs could vary from amounts accrued. At December 31, 2008, the accrued liability for depleted uranium is $119.5 million and the accrued liability for lease turnover costs is $55.4 million.
     American Centrifuge Technology Costs
     Costs relating to the American Centrifuge technology are charged to expense or capitalized based on the nature of the activities and estimates and judgments involving the completion of project milestones. Costs relating to the demonstration of American Centrifuge technology are charged to expense as incurred. Demonstration costs historically have included NRC licensing of the American Centrifuge Demonstration Facility in Piketon, Ohio, engineering activities, and assembling and testing of centrifuge machines and equipment at centrifuge test facilities located in Oak Ridge, Tennessee and at the American Centrifuge Demonstration Facility.
     Capitalized costs relating to the American Centrifuge technology include NRC licensing of the American Centrifuge Plant in Piketon, Ohio, engineering activities, construction of centrifuge machines and equipment, leasehold improvements and other costs directly associated with the commercial plant. Capitalized centrifuge costs are recorded in property, plant and equipment as part of construction work in progress. The continued capitalization of such costs is subject to ongoing review and successful project completion. During the second half of 2007, we moved from a demonstration phase to a commercial plant phase in which significant expenditures are capitalized based on management’s judgment that the technology has a high probability of commercial success and meets internal targets related to physical control, technical achievement and economic viability.
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If conditions change and deployment were no longer probable, costs that were previously capitalized would be charged to expense.
     As we continue construction of the American Centrifuge Plant, we create asset retirement obligations based on our requirements to decontaminate and decommission (“D&D”) the facility. The present value of an asset retirement obligation is recognized as a liability and an equivalent amount is recognized as part of the capitalized asset cost. The liability is accreted, or increased, over time for the time value of money. The accretion is charged to cost of sales. Upon commencement of commercial operations, the asset cost will be depreciated over the shorter of the asset life or the expected lease period. During each reporting period, we reassess and revise the estimate of asset retirement obligations based on construction progress, cost evaluation of future D&D expectations, and other judgmental considerations.
     Income Taxes
     During the ordinary course of business, there are transactions and calculations for which the ultimate tax determination is uncertain. As a result, we recognize tax liabilities based on estimates of whether additional taxes and interest will be due. To the extent that the final tax outcome of these matters is different than the amounts that were initially recorded, such differences will impact the income tax provision in the period in which such determination is made. If the provision for income taxes increases/decreases by 1% of income from continuing operations, net income would have declined/improved by $0.7 million in 2008.
     Accounting for income taxes involves estimates and judgments relating to the tax bases of assets and liabilities and the future recoverability of deferred tax assets. In assessing the realization of deferred tax assets, we determine whether it is more likely than not that the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon generating sufficient taxable income in future years when deferred tax assets are recoverable or are expected to reverse. Factors that may affect estimates of future taxable income include, but are not limited to, competition, changes in revenue, costs or profit margins, market share and developments related to the American Centrifuge Plant. We have determined that it is more likely than not that deferred tax assets will be realized. At December 31, 2008, our net deferred tax assets were $341.2 million.
     Determining the need for or the amount of a valuation allowance involves judgments, estimates and assumptions. We review historical results, forecasts of taxable income based upon business plans, eligible carryforward periods, periods over which deferred tax assets are expected to reverse, developments related to the American Centrifuge Plant, tax planning opportunities, and other relevant considerations. The underlying assumptions may change from period to period. If we were to determine that it is more likely than not that all or some of the deferred tax assets will not be realized in future years, a valuation allowance would result.
     In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), which became effective January 1, 2007. This interpretation clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before the related tax benefit may be recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. At December 31, 2008, the liability for unrecognized tax benefits, included in other long-term liabilities, was $3.8 million and accrued interest and penalties totaled $0.9 million.
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Results of Operations
     We have two reportable segments measured and presented through the gross profit line of our income statement: the low enriched uranium (“LEU”) segment with two components, separative work units (“SWU”) and uranium, and the U.S. government contracts segment. The LEU segment is our primary business focus and includes sales of the SWU component of LEU, sales of both SWU and uranium components of LEU, and sales of uranium. The U.S. government contracts segment includes work performed for DOE and its contractors at the Portsmouth and Paducah GDPs as well as nuclear energy services and technologies provided by NAC. Intersegment sales between our reportable segments were less than $0.1 million in each year presented below and have been eliminated in consolidation.
     2008 Compared to 2007
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2008	 	 	2007	 	 	Change	 	 	%	 	
 	 	(millions)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LEU segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SWU revenue	 	$	1,175.5	 	 	$	1,570.5	 	 	$	(395.0	)	 	 	(25	)%	
Uranium revenue	 	 	217.1	 	 	 	163.5	 	 	 	53.6	 	 	 	33	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	1,392.6	 	 	 	1,734.0	 	 	 	(341.4	)	 	 	(20	)%	
Cost of sales	 	 	1,202.2	 	 	 	1,473.6	 	 	 	271.4	 	 	 	18	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	$	190.4	 	 	$	260.4	 	 	$	(70.0	)	 	 	(27	)%	

U.S. government contracts segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	$	222.0	 	 	$	194.0	 	 	$	28.0	 	 	 	14	%	
Cost of sales	 	 	183.6	 	 	 	166.9	 	 	 	(16.7	)	 	 	(10	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	$	38.4	 	 	$	27.1	 	 	$	11.3	 	 	 	42	%	

Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	$	1,614.6	 	 	$	1,928.0	 	 	$	(313.4	)	 	 	(16	)%	
Cost of sales	 	 	1,385.8	 	 	 	1,640.5	 	 	 	254.7	 	 	 	16	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	$	228.8	 	 	$	287.5	 	 	$	(58.7	)	 	 	(20	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     Revenue
     The volume of SWU sold declined 27% in 2008 compared to 2007 due to the timing of utility customer refuelings. Because a majority of the reactors served by USEC are refueled on an 18-to-24 month cycle, we anticipate deliveries in 2009 roughly similar to 2007. The average price billed to customers for sales of SWU increased 2% reflecting the particular contracts under which SWU was sold during the periods as well as the general trend of higher prices under contracts signed in recent years. There was no revenue under barter contracts in 2008. In 2007, revenue from the sales of SWU under barter contracts, based on the estimated fair value of uranium received in exchange for SWU, was $50.8 million.
     The volume of uranium sold in 2008 compared to 2007 declined 4% and the average price increased 38% reflecting the timing of customer orders and the particular price mix of contracts under which uranium was sold.
     Revenue from the U.S. government contracts segment increased 14% in 2008 compared to 2007. Revenue for contract work at the Portsmouth GDP increased $18.8 million to $176.2 million in 2008. This increase was related to cold shutdown efforts and incremental revenue for fiscal 2002 DOE contract work based on the resolution of concerns regarding billable incurred costs. Revenue for contract work at the Paducah GDP also increased by $1.2 million to $12.7 million in 2008. Revenue for contract work at NAC increased $8.0 million to $33.1 million in 2008 due to the timing of sales for NAC.
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     As of December 31, 2008, we have finalized and submitted to DOE the billable incurred costs for Portsmouth and Paducah GDP contract work for the six months ended December 31, 2002 and the years ended December 31, 2003, 2004, 2005, 2006 and 2007. At December 31, 2008, $4.6 million, reflecting the elimination of allowances associated with estimates contained in the provisional billing rates, was recognized. Additional revenue based on the difference between provisional billing rates and final billing rates will be recognized upon completion of the DCAA audit and notice by DOE authorizing final billing.
     Cost of Sales
     Cost of sales for SWU and uranium declined $271.4 million (or 18%) in 2008 compared to 2007 due to the declines in volumes sold partially offset by higher unit costs. Under our monthly moving average cost method, new production and acquisition costs are averaged with the cost of inventories at the beginning of the period. Cost of sales per SWU was 4% higher in 2008 compared to 2007.
     Production costs increased $108.5 million (or 14%) in 2008 compared to 2007 primarily due to a 10% increase in overall production volume and an increase in the average cost of electric power. Unit production costs increased 3%. The cost of electric power increased by $104.7 million year-to-year, reflecting an additional 1.6 million megawatt hours purchased in 2008, an increase of 12%. The increase in production volume and power purchased resulted in a 2% decline in our electric power usage efficiency. The average cost per megawatt hour increased 6% driven by TVA fuel cost adjustments and higher costs for supplemental power purchased at market-based prices.
     Purchase costs for the SWU component of LEU under the Russian Contract increased $53.0 million in 2008 compared to 2007 due to an 11% increase in the market-based purchase cost per SWU. Purchase prices paid under the Russian Contract are set by a market-based pricing formula and have increased as market prices have increased in recent years.
     Cost of sales for the U.S. government contracts segment increased $16.7 million (or 10%) primarily due to increased contract work related to cold shutdown efforts and NAC timing of sales.
     Gross Profit
     Our gross profit margin was 14.2% in 2008 compared to 14.9% in 2007 reflecting lower margins in the LEU segment slightly offset by higher margins in the U.S. government contracts segment.
     Gross profit for SWU and uranium declined $70.0 million in 2008 compared to 2007 due to lower SWU sales volume and higher inventory costs, partly offset by higher average sales prices for SWU and uranium.
     Gross profit for the U.S. government contracts segment increased $11.3 million in 2008 compared to 2007 due to increased contract work related to cold shutdown efforts at the Portsmouth GDP, incremental revenue for fiscal 2002 DOE contract work based on the resolution of concerns regarding billable incurred costs, and the elimination of allowances associated with estimates contained in the provisional billing rates for the six months ended December 31, 2002 and the years ended December 31, 2003, 2004, 2005, 2006 and 2007.
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     The following table presents elements of the accompanying consolidated statements of income that are not categorized by segment (amounts in millions, except percentages):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2008	 	 	2007	 	 	Change	 	 	%	 	
Gross profit	 	$	228.8	 	 	$	287.5	 	 	$	(58.7	)	 	 	(20	)%	
Advanced technology costs	 	 	110.2	 	 	 	127.3	 	 	 	17.1	 	 	 	13	%	
Selling, general and administrative	 	 	54.3	 	 	 	45.3	 	 	 	(9.0	)	 	 	(20	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	64.3	 	 	 	114.9	 	 	 	(50.6	)	 	 	(44	)%	
Interest expense	 	 	17.3	 	 	 	16.9	 	 	 	(0.4	)	 	 	(2	)%	
Interest (income)	 	 	(24.7	)	 	 	(33.8	)	 	 	(9.1	)	 	 	(27	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income before income taxes	 	 	71.7	 	 	 	131.8	 	 	 	(60.1	)	 	 	(46	)%	
Provision for income taxes	 	 	23.0	 	 	 	35.2	 	 	 	12.2	 	 	 	35	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	48.7	 	 	$	96.6	 	 	$	(47.9	)	 	 	(50	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     Advanced Technology Costs
     The decrease in advanced technology costs reflects reduced demonstration costs for the American Centrifuge technology. Demonstration costs associated with assembling and testing of centrifuge machines and equipment at our Oak Ridge test facilities has declined as spending has increased in activities related to capitalized construction work in progress on the centrifuge machines and American Centrifuge Plant. Demonstration costs for the American Centrifuge technology were $108.8 million in 2008 compared to $125.9 million in 2007. The remaining amounts included in advanced technology costs are efforts by NAC to develop its MAGNASTOR storage system.
     Selling, General and Administrative
     Compensation and benefit expenses increased $2.1 million in 2008 compared to 2007 reflecting the low level of stock-based compensation expense in 2007 that resulted from a decline in our stock price. Consulting costs increased $1.9 million primarily related to strategy, enterprise risk management, and organizational efforts. Travel costs increased $1.1 million primarily related to additional corporate travel related to the American Centrifuge project. Selling, general, and administrative expenses in 2007 reflect the reversal of a previously accrued tax penalty of $3.4 million.
     Interest Expense and Interest Income
     Interest expense increased $0.4 million (or 2%) reflecting a full year of interest in 2008 on our 3.0% convertible senior notes or an increase of approximately $12.8 million, offset by increased interest amounts capitalized related to American Centrifuge of approximately $8.4 million, as well as reductions in interest expense as we repaid a portion of our 6.75% senior notes. In addition, accrued interest expense for taxes decreased $2.8 million period to period reflecting the reduction in our FIN 48 liability.
     Interest income declined $9.1 million (or 27%) in 2008 compared to 2007. Interest income in 2007 benefited from reversals of previously accrued interest expense on taxes and interest expense recorded upon the adoption of FIN 48 effective January 1, 2007. These reversals related to the expiration of the U.S. federal statute of limitations with respect to tax return years 1998 through 2003 and agreement on outstanding matters reached with the IRS during the second quarter of 2007. Partially offsetting the decline in interest income was a $2.2 million increase of interest income on short-term investments in 2008 as a result of increased cash and investment balances following our issuance of convertible notes and common stock in September 2007.
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     Provision for Income Taxes
     The provision for income taxes in 2008 was $23.0 million, including benefits of $4.4 million primarily due to reversals of previously accrued amounts under accounting guidance provided in FIN 48 of $2.9 million and an increase in research credits of $1.5 million for 2007 which resulted from a research credit study completed in the third quarter 2008. The reversals of FIN 48 liabilities in 2008 of $2.9 million primarily resulted from the completion of IRS federal income tax audits for 2004 through 2006. The provision for income taxes of $35.2 million in 2007 included $12.6 million in benefits due to reversals of accruals previously recorded and those associated with the adoption of FIN 48. These reversals primarily resulted from the expiration of the U.S. federal statute of limitations with respect to tax return years 1998 through 2003.
     Excluding the effects of FIN 48 and research credit related adjustments, the overall effective income tax rate was 38% in 2008 and 36% in 2007. The increase is primarily due to decreases in income before income taxes, the manufacturing deduction, and the FIN 48 penalty reversal, offset by the increase in the federal research credit. In October 2008, the federal research credit was extended through December 31, 2009.
     Net Income
     Net income declined $47.9 million (or $0.60 per share—basic and $0.59 per share-diluted) in 2008 compared to 2007 due primarily to the after-tax impact of lower gross profits in the LEU segment due to lower SWU sales volume, which was a result of the timing of utility customer refuelings, and higher inventory costs, partially offset by higher average sales prices for SWU and uranium. The decline was partially offset by lower advanced technology expenses. In addition, the corresponding period in 2007 benefited by $22.1 million from the impact of reversals of accruals previously recorded and those associated with the adoption of FIN 48, released upon the U.S. federal statute of limitations expiration with respect to tax return years 1998 through 2003 and the completion of the IRS examination for all tax years through 2003. The decline in net income per share also reflects our issuance of 23 million shares of common stock in September 2007.
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2007 Compared to 2006
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	Change	 	 	%	 	
 	 	(millions)	 	 	 	 	 	
LEU segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SWU revenue	 	$	1,570.5	 	 	$	1,337.4	 	 	$	233.1	 	 	 	17	%	
Uranium revenue	 	 	163.5	 	 	 	316.7	 	 	 	(153.2	)	 	 	(48	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	1,734.0	 	 	 	1,654.1	 	 	 	79.9	 	 	 	5	%	
Cost of sales	 	 	1,473.6	 	 	 	1,349.2	 	 	 	(124.4	)	 	 	(9	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	$	260.4	 	 	$	304.9	 	 	$	(44.5	)	 	 	(15	)%	

U.S. government contracts segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	$	194.0	 	 	$	194.5	 	 	$	(0.5	)	 	 	0	%	
Cost of sales	 	 	166.9	 	 	 	162.5	 	 	 	(4.4	)	 	 	(3	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	$	27.1	 	 	$	32.0	 	 	$	(4.9	)	 	 	(15	)%	

Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue	 	$	1,928.0	 	 	$	1,848.6	 	 	$	79.4	 	 	 	4	%	
Cost of sales	 	 	1,640.5	 	 	 	1,511.7	 	 	 	(128.8	)	 	 	(9	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	$	287.5	 	 	$	336.9	 	 	$	(49.4	)	 	 	(15	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     Revenue
     The volume of SWU sold increased 8% in 2007 compared to 2006 and the average price billed to customers increased 9%. The increase in volume reflects net increases in purchases by customers and the timing of utility customer refuelings. The increase in the average price reflects higher prices charged to customers under contracts signed in recent years, price increases from contractual provisions for inflation and market adjustments, and the mix of deliveries under newer versus older contracts.
     Revenue from the sales of SWU under barter contracts, based on the estimated fair value of uranium received in exchange for SWU, was $50.8 million in 2007 and $12.5 million in 2006.
     The volume of uranium sold decreased 60% reflecting declines in our inventory of uranium available for sale. The average price for uranium delivered increased 29% reflecting higher-priced contracts signed with customers in recent years.
     Revenue from the U.S. government contracts segment declined less than 1% in 2007 compared to 2006. Revenue for contract work at the Portsmouth GDP increased $0.7 million in 2007 due to an additional scope of work performed under the cold shutdown contract partially offset by a reduction resulting from the completion of the legacy centrifuge equipment removal project in August 2006. Revenue for contract work at the Paducah GDP and NAC slightly declined in 2007 compared to 2006 offsetting the Portsmouth GDP increase.
     Cost of Sales
     Cost of sales for SWU and uranium increased $124.4 million (or 9%) in 2007 compared to 2006 primarily due to the 8% increase in the volume of SWU sold. Cost of sales per SWU was 7% higher reflecting increases in average inventory costs. Under our monthly moving average cost method, new production and acquisition costs are averaged with the cost of inventories at the beginning of the period.
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     Production costs increased $157.2 million (or 25%), primarily due to increases in the cost of electric power. Production levels increased 9% and unit production costs increased 14%. The cost for electric power increased $147.3 million, reflecting an increase in the average cost per megawatt hour and an increase in megawatt hours purchased. The average cost per megawatt hour increased 22%, reflecting higher prices under the TVA power contract effective June 2006. The utilization of electric power, a measure of production efficiency, was about the same in 2007 as in 2006.
     Purchase costs for the SWU component of LEU under the Russian Contract increased $23.4 million due to increases in the market-based purchase cost per SWU. Purchase prices paid under the Russian Contract are set by a market-based pricing formula and have increased as market prices have increased in recent years.
     Cost of sales for the U.S. government contracts segment increased $4.4 million (or 3%) primarily due to sales of lower margin contract services at NAC.
     Gross Profit
     Our gross profit margin was 14.9% in 2007 compared to 18.2% in 2006 reflecting lower margins in both segments.
     Gross profit for the LEU segment declined $44.5 million (or 15%) in 2007 compared to 2006. The positive impact of increases in SWU and uranium sales prices was reduced in 2007 compared to 2006 as higher production and purchase costs were recognized in cost of sales. In addition, the decline in uranium sales reflects reduced uranium available for sale.
     Gross profit for the U.S. government contracts segment declined $4.9 million (or 15%) due to sales of lower margin contract services at NAC.
     The following table presents elements of the accompanying consolidated statements of income that are not categorized by segment (amounts in millions, except percentages):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	Change	 	 	%	 	
Gross profit	 	$	287.5	 	 	$	336.9	 	 	$	(49.4	)	 	 	(15	)%	
Special charges	 	 	—	 	 	 	3.9	 	 	 	3.9	 	 	 	—	 	
Advanced technology costs	 	 	127.3	 	 	 	105.5	 	 	 	(21.8	)	 	 	(21	)%	
Selling, general and administrative	 	 	45.3	 	 	 	48.8	 	 	 	3.5	 	 	 	7	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	114.9	 	 	 	178.7	 	 	 	(63.8	)	 	 	(36	)%	
Interest expense	 	 	16.9	 	 	 	14.5	 	 	 	(2.4	)	 	 	(17	)%	
Interest (income)	 	 	(33.8	)	 	 	(6.2	)	 	 	27.6	 	 	 	445	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income before income taxes	 	 	131.8	 	 	 	170.4	 	 	 	(38.6	)	 	 	(23	)%	
Provision for income taxes	 	 	35.2	 	 	 	64.2	 	 	 	29.0	 	 	 	45	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	96.6	 	 	$	106.2	 	 	$	(9.6	)	 	 	(9	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     Special Charges
     Special charges in 2006 consisted of $1.3 million related to an organizational restructuring and $2.6 million resulting from the impairment of an intangible asset related to the 2004 acquisition of NAC. The acquisition cost allocated to customer contracts and relationships from the NAC acquisition was reduced after DOE set aside certain contract work for small businesses for which NAC did not qualify.
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     Advanced Technology Costs
     The increase in advanced technology costs reflects increased demonstration costs for the American Centrifuge technology. NAC-related advanced technology costs were $1.3 million in 2007 and $2.1 million in 2006.
     Selling, General and Administrative
     The decline in selling, general, and administrative expenses reflects a reversal in 2007 of a previously accrued tax penalty of $3.4 million. We reached agreement with the IRS during the second quarter of 2007 on certain deductions related to expenditures made in the tax return years 1998 through 2000. Consulting expenses declined $0.8 million in 2007 compared to 2006. Offsetting these improvements were increased stock-based compensation expenses resulting primarily from vesting of participants in our equity compensation plans.
     Interest Expense and Interest Income
     Interest expense increased in 2007 compared to 2006 due to accrued interest on our $575.0 million of convertible notes issued in September 2007, and increases of accrued interest for taxes. The increase is partly offset by an increase of $3.2 million in capitalized interest related to the American Centrifuge Plant and our repayment of $288.8 million of our 6.625% senior notes on the scheduled maturity date in January 2006.
     Interest income increased due, in large part, to reversals of previously accrued interest expense on taxes and interest expense recorded upon the adoption of FIN 48 effective January 1, 2007. These reversals relate to the expiration of the U.S. federal statute of limitations with respect to tax return years 1998 through 2003 and agreement on outstanding matters reached with the IRS during the second quarter of 2007. The increase in interest income is also due to increased cash and investment balances resulting from the proceeds from our issuances of convertible notes and common stock in September 2007.
     Provision for Income Taxes
     The provision for income taxes in 2007 was $35.2 million with an overall effective income tax rate of 27%. We recorded the effects of $12.6 million of tax benefits due to reversals of accruals previously recorded and those associated with the adoption of FIN 48 effective January 1, 2007. Excluding these effects, our effective tax rate would have been 36% in 2007. The most significant items in the remaining difference between the effective tax rate in 2007 as compared to the statutory federal and state income tax rate include the positive effects related to our manufacturing deduction and research and other tax credits.
     The provision for income taxes in 2006 was $64.2 million with an overall effective income tax rate of 38%. Differences between the effective tax rate in 2006 as compared to the statutory federal and state income tax rate include the effects of state deferred tax asset reductions offset by research and other tax credits.
     Net Income
     Net income declined $9.6 million (or $0.18 per share—basic and diluted) in 2007 compared to 2006, reflecting the after-tax impacts of lower gross profits and higher American Centrifuge demonstration costs, partly offset by $22.1 million of tax-related effects from the impact of reversals of accruals previously recorded and those associated with the adoption of FIN 48, released upon the U.S. federal statute of limitations expiration with respect to tax return years 1998 through 2003 and the completion of the IRS examination for all tax years through 2003. The decline in net income per share also reflects our issuance of 23 million shares of common stock in September 2007.
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2009 Outlook
     As expressed in previous guidance, we expect the volume of SWU sold in 2009 to return to a level similar to that seen in 2007. Because a majority of our customers refuel their reactors on an 18-to-24 month cycle, those customers who refueled reactors in 2007 are likely to require LEU again in 2009. In the past five years, we have sold roughly 10 to 13 million SWU per year, and we expect to exceed the high end of that range in 2009.
     We expect total revenue in the range of $2.2 to $2.25 billion in 2009. Revenue from SWU sales is expected to be approximately $1.8 billion, or about 50% higher than 2008. SWU volume is expected to be approximately 40% higher and the average price billed to customers is expected to be 10% higher. Revenue from uranium is expected to decline to just under $200 million in 2009 as spot uranium prices gradually fell during 2008. The recognition of this revenue is subject to the timing of uranium used as feed stock in LEU deliveries. Revenue from government services and other is expected to be relatively flat at about $220 million in 2009.
     Electric power represents 70% to 75% of our cost of production at the Paducah GDP. We have a contract with the Tennessee Valley Authority to purchase 2,000 megawatts of power during the non-summer months of 2009 at a fixed base price that increased slightly over 2008. Under this contract we also pay an adjustment to reflect the cost of fuel or purchased power above or below the cost assumed in that base price. The fuel cost adjustment averaged 15% above the base price in 2008 and TVA has continued to forecast increased fuel and purchased power costs for 2009. The uncertainty of fuel prices in the current economic climate results in difficulty in predicting this major production cost component, and variations from our forecast can significantly affect results. We produce about half of our supply and purchase half from Russia under the Megatons to Megawatts program. Under the program’s market-based pricing formula, we expect to pay Russia about 11% more for LEU purchased in 2009, compared to 2008, reflecting increases in SWU market price indicators in recent years.
     Our cost of sales, reflecting higher production and purchase costs rolling through our inventory, is increasing faster than our average price billed to customers. This has put pressure on our gross margin in recent years and that trend is expected to continue in 2009. Thus, although our average price billed to customers is expected to improve from last year, the expected increase in cost of sales is greater. We expect our gross profit margin in 2009 to be between 10% and 12%, compared to 14.2% in 2008.
     The sharp downturn in the fair value of pension and postretirement benefit plan assets, due primarily to market conditions from 2008, will also result in higher net benefit costs in 2009. These net benefit costs are embedded in our costs for both business segments, as well as selling, general and administrative (“SG&A”) expense. Combined, this net benefit cost is estimated to be approximately $51 million higher than in 2008 and will also require us to fund these plans by approximately $15 million more than in 2008.
     Below the gross profit line, we expect SG&A expense to be approximately $57 million in 2009. We expect our income tax rate will be close to the combined federal and state statutory rate. Although much of our spending on the American Centrifuge Plant is anticipated to be capitalized, we expect to continue development and value engineering efforts that are expensed. We expect to expense roughly $120 million of spending during 2009. In addition, our baseline plan for ACP capital expenditures in 2009 is approximately $700 million but this amount will be affected by our announced plan to slow down spending on the ACP, as discussed in “Liquidity and Capital Resources”.
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     Based on these projections, we anticipate net income in a range of $25 to $50 million for 2009. Cash flows from operations in 2008 were negative in part due to a build-up of SWU inventory in advance of higher anticipated SWU deliveries in 2009. This inventory is expected to be monetized in 2009, thus substantially improving cash flow from operations, year over year. Although we expect higher disbursements for electric power, increased purchase costs from Russia and continued significant ACP spending that is expensed, we anticipate cash flow generated from operations in a range of $240 to $275 million.
     Our financial results guidance is subject to a number of assumptions and uncertainties that could affect results either positively or negatively. Variations from our expectations could cause substantial differences between our guidance and ultimate results. Among the factors that could affect net income and cash flows are:
 	•	 	Changes to the electric power fuel cost adjustment from our current projection;	
 	 	 	 	
 	•	 	The potential for significantly reduced ACP spending as a result of our announced plan to slow down project spending;	
 	 	 	 	
 	•	 	The amount of spending on the ACP that is classified as an expense;	
 	 	 	 	
 	•	 	The timing of recognition of previously deferred revenue, particularly related to the sale of uranium;	
 	 	 	 	
 	•	 	Movement and timing of customer orders;	
 	 	 	 	
 	•	 	Changes in SWU and uranium market price indicators, and changes in inflation that can affect the price of SWU billed to customers; and	
 	 	 	 	
 	•	 	Additional uranium sales made possible by underfeeding the production process at the Paducah GDP.	
Liquidity and Capital Resources
     We provide for our liquidity requirements through our cash balances, working capital and access to our bank credit facility. Our cash needs include the funding of American Centrifuge project activities.
     We had a cash balance of $248.5 million as of December 31, 2008 compared to $886.1 million at December 31, 2007. We need to raise a significant amount of additional capital to continue funding and to complete the American Centrifuge Plant. We do not believe public market financing for a large capital project such as the American Centrifuge Plant is available to us given current financial market conditions. In July 2008, we applied to the DOE Loan Guarantee Program as the path for obtaining $2 billion in debt financing to complete the American Centrifuge Plant. Areva, a company majority owned by the French government, also applied for funding under this program for a proposed plant in the U.S. and is also being considered by DOE. We are seeking a selection of our project by DOE in the short term, followed by an expeditious funding commitment and financial closing. However, we have no assurance that our project will be selected to move forward in the program, and if we are selected, it could still take an extended period for the loan guarantee and funding to be finalized. Accordingly, we have initiated steps to conserve cash and reduce the planned escalation of project construction and machine manufacturing activities until we gain greater clarity on potential funding for the project through the DOE Loan Guarantee Program. In addition, on a parallel path, we continue to evaluate potential third-party investment.
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     Our intent is to reduce our spending in 2009 to work within the combination of our expected funds available through our cash from operations and available borrowings under our credit facility and ensure that we have adequate liquidity for our ongoing operations. Under our deployment schedule for the ACP, spending was expected to peak in 2009 with spending of approximately $800 million, including a substantial ramp up in coming months with the hiring of plant construction workers and preparing facilities that would provide key components for the AC100 centrifuge machines. Our initial steps to slow the growth of project spending in 2009 include sharply reducing the ramp up in hiring construction and craft workers for the ACP and deferring select procurements. We are working with our suppliers to identify and implement actions that can be taken to reduce costs while minimizing the impact on project cost and schedule. We may also take other actions to ensure that we have adequate liquidity for our ongoing operations and remain in compliance with covenants under our debt agreements. Further details are provided in “— Capital Structure and Financial Resources” and Part I, Item 1A, “Risk Factors” of this report.
     Without a DOE loan guarantee or other financing and without taking into account our plans to slow down project spending in 2009, we anticipate that our cash, expected internally generated cash flow from operations and available borrowings under our revolving credit facility would be sufficient to meet our cash needs for approximately 6-9 months under our baseline budget and schedule. Taking into account our plans to slow down project spending, we anticipate that our liquidity will be sufficient beyond this period. If we determine that a loan guarantee or alternative financing is not forthcoming or available in the near term, we will take additional steps to implement further project spending reductions to maintain sufficient liquidity for at least twelve months. However, additional funds may be necessary sooner than we currently anticipate if we are not successful in our efforts to conserve cash or in the event of increases in the cost of the American Centrifuge project, unanticipated prepayments to suppliers, increases in financial assurance, unanticipated costs under the Russian Contract, increases in power costs or any shortfall in our estimated levels of operating cash flow, or to meet other unanticipated expenses.
     We believe the Paducah GDP provides a meaningful operational backstop during the ACP deployment period and we have the flexibility to extend its operations as part of any alternative planning we may evaluate as the most prudent path for deploying the ACP.
     The change in cash and cash equivalents from our consolidated statements of cash flows are as follows on a summarized basis (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
Net cash provided by (used in) operating activities	 	$	(104.9	)	 	$	109.2	 	 	$	278.1	 	
Net cash (used in) investing activities	 	 	(477.2	)	 	 	(170.4	)	 	 	(79.6	)	
Net cash provided by (used in) financing activities	 	 	(55.5	)	 	 	775.9	 	 	 	(286.2	)	
 	 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	$	(637.6	)	 	$	714.7	 	 	$	(87.7	)	
 	 	 	 	 	 	 	 	 	 	
     Operating Activities
     During 2008, net cash used in operating activities was $104.9 million. Net inventory balances grew $270.6 million reflecting increased production volume and costs and a build-up of SWU inventory in advance of higher anticipated SWU deliveries in 2009. An additional use of cash flow was an increase in prepaid power costs of $17.7 million related to the TVA fuel adjustment and prepaid taxes of $20.9 million. A decrease in accounts receivable of $98.8 million in 2008 following strong sales in the fourth quarter of 2007 and increased deferred profits relating to uranium and LEU that were sold but not shipped during the year provided increased cash flow. Results of operations in 2008 contributed $48.7 million to cash flow and $34.2 million in non-cash adjustments for depreciation and amortization.
     During 2007, we generated net cash flow from operating activities of $109.2 million. Results of operations of $96.6 million and $39.5 million in non-cash adjustments for depreciation and amortization contributed to our operating cash. Results of operations include approximately $22.1 million of non-cash related reversals of tax-related accruals previously recorded and those associated with the adoption of FIN 48. These increases in cash flow were slightly offset by the timing of other balance sheet items.
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     During 2006, we generated net cash flow from operating activities of $278.1 million. Results of operations contributed $106.2 million to cash flow and $36.7 million in non-cash adjustments for depreciation and amortization. A reduction in net inventory balances of $176.1 million period to period also contributed to cash flow, as we sold from existing inventories as well as from current production. Reductions in accounts payable and other liabilities reduced cash flow from operations by $82.1 million during the period, principally from tax payments, prepayment modifications under the amended TVA contract, and payments to our former president and chief executive officer in settlement of his claims. The timing of other balance sheet items, principally the timing of accounts receivable collections, also contributed to the increase in cash flow.
     Investing Activities
     Capital expenditures were $441.9 million in 2008, $137.2 million in 2007 and $44.8 million in 2006. Capital expenditures during these periods are principally associated with the American Centrifuge Plant, including prepayments made to suppliers for services not yet performed. Cash deposits are made as collateral for surety bonds were $35.3 million in 2008, $33.2 million in 2007 and $34.8 million in 2006. The surety bonds represent financial assurance relating primarily to the future disposition of depleted uranium generated in our enrichment process and American Centrifuge decontamination and decommissioning.
     Financing Activities
     There were no short-term borrowings under the credit facility at December 31, 2008 or at December 31, 2007. Aggregate borrowings and repayments under the revolving credit facility in 2008 were $48.3 million, and the peak amount outstanding was $37.4 million. In 2008, we repurchased $54.3 million of the 6.75% senior notes due January 20, 2009. The cost of the repurchase was $52.8 million and was net of a discount of $1.5 million. Subsequently, we repaid the remaining principal balance of $95.7 million on the scheduled maturity date of January 20, 2009 with available cash.
     In September 2007, we raised net proceeds, after underwriter commissions and offering expenses, of approximately $775 million through the concurrent issuance of 23 million shares of common stock and $575 million in aggregate principal amount of convertible notes. Other issuances of common stock, primarily from employee stock-based compensation plans, provided cash flow from financing activities of $0.1 million in 2008, $0.5 million in 2007, and $2.5 million in 2006. There were 111.8 million shares of common stock outstanding at December 31, 2008, compared with 110.6 million at December 31, 2007, an increase of 1.2 million shares (or 1%) and 87.1 million at December 31, 2006, or an increase from 2006 to 2007 of 23.5 million shares (or 27%).
     In January 2006, we repaid the remaining principal balance of our 6.625% senior notes of $288.8 million on the scheduled maturity date using cash on hand and borrowing under our bank credit facility of approximately $78.5 million. We repaid the $78.5 million borrowing with funds from operations by the end of January 2006.
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     Working Capital
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
 	 	(millions)	 	
Cash and cash equivalents	 	$	248.5	 	 	$	886.1	 	
Accounts receivable	 	 	154.1	 	 	 	252.9	 	
Inventories, net	 	 	1,101.7	 	 	 	831.1	 	
Current portion of long-term debt	 	 	(95.7	)	 	 	—	 	
Other current assets and liabilities, net	 	 	(234.3	)	 	 	(255.3	)	
 	 	 	 	 	 	 	
Working capital	 	$	1,174.3	 	 	$	1,714.8	 	
 	 	 	 	 	 	 	
     The decline in working capital of $540.5 million reflects cash used in investing activities of $477.2 million in 2008, principally for capitalized expenditures associated with the American Centrifuge Plant. At December 31, 2008, the current portion of long-term debt consisted of the remaining balance of the 6.75% senior notes, which were paid in full on the scheduled maturity date of January 20, 2009. The increase in net inventories reflects a temporary build-up in anticipation of a greater volume of near-term SWU sales.
     Capital Structure and Financial Resources
     At December 31, 2008, our long-term debt consisted of $575.0 million in 3.0% convertible senior notes due October 1, 2014. These notes are unsecured obligations and rank on a parity with all of our other unsecured and unsubordinated indebtedness. Financing costs of $14.3 million related to the convertible notes were deferred and are being amortized over the life of the debt. The current portion of long-term debt, included in current liabilities, consisted of $95.7 million of 6.75% senior notes which were paid in full at maturity on January 20, 2009.
     In August 2005, we entered into a five-year, syndicated bank credit facility, providing up to $400.0 million in revolving credit commitments, including up to $300.0 million in letters of credit, secured by assets of USEC Inc. and our subsidiaries. The credit facility is available to finance working capital needs and fund capital programs, including the American Centrifuge project. Financing costs of $3.5 million and $0.3 million to obtain and amend the credit facility, respectively, were deferred and are being amortized over the five-year life.
     There were no short-term borrowings under the revolving credit facility at December 31, 2008 or December 31, 2007. Letters of credit issued under the facility amounted to $48.0 million at December 31, 2008 and $38.4 million at December 31, 2007.
     Outstanding borrowings under the credit facility bear interest at a variable rate, which at our election is equal to either:
 	•	 	the sum of (1) the greater of the JPMorgan Chase Bank prime rate and the federal funds rate plus1/2 of 1%, plus (2) a margin ranging from 0.25% to 0.75% based upon collateral availability, or	
 	 	 	 	
 	•	 	the sum of LIBOR plus a margin ranging from 2.0% to 2.5% based on collateral availability.	
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     Borrowings under the credit facility are subject to limitations based on established percentages of qualifying assets such as eligible accounts receivable and inventory. The credit facility contains various reserve provisions that reduce available borrowings under the facility periodically or restrict the use of borrowings if certain requirements are not met, including those listed below.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	December 31,	 	
 	 	Requirement	 	 	2008	 	 	2007	 	
 	 	(millions)	 	
Available Credit	 	 	 	 	 	$	343.0	 	 	$	361.6	 	
Credit facility provisions:	 	 	 	 	 	 	 	 	 	 	 	 	
Availability	 	 	³ $35.0	 	 	$	342.3	 	 	$	360.9	 	
Collateral Availability	 	 	³ $75.0	 	 	$	342.3	 	 	$	393.3	 	
Available Liquidity	 	 	³ $125.0	 	 	$	591.5	 	 	$	1,247.7	 	
     As of December 31, 2008 and 2007, we met all of the reserve provision requirements by a large margin. However, we expect to have borrowings under the credit facility in 2009, which will reduce Availability, Collateral Availability and Available Liquidity.
     “Available Credit” reflects the levels of qualifying assets at the end of the previous month less any borrowings or letters of credit, and will fluctuate during the year. Qualifying assets are reduced by certain reserves, principally a reserve for future obligations to DOE with respect to the turnover of the gaseous diffusion plants at the end of the term of the lease of these facilities.
     “Availability” means, the lesser of (i) $400 million and (ii) the sum of eligible receivables and eligible inventory, subject to caps, less the sum of letters of credit issued, outstanding loan balances and accrued interest, fees and expenses. Availability equals Available Credit less accrued interest, fees and expenses.
     “Collateral Availability” means the sum of eligible receivables and eligible inventory, subject to caps, minus the outstanding loans, letters of credit issued and accrued interest, fees and expenses.
     “Available Liquidity” means Availability plus cash balances in accounts controlled by the administrative agent.
     Additional details regarding these reserve provisions follow.
 	 	 	
Requirement	 	Outcome	
 	 	 	
Availability ³ $35 million	 	If not met at any time, an event of default is triggered.	
 	 	 	
Collateral Availability ³ $75 million	 	If not met for 7 consecutive days, then fixed charge ratio required to be 1.00 to 1.00 until the 90 th  consecutive day Collateral Availability is restored to $75 million.	
 	 	 	
Available Liquidity ³ $125 million	 	If not met for 7 consecutive days, non-financed capital expenditures are limited to $50 million until the 90 th  consecutive day Available Liquidity is restored to $125 million.	
     Other reserves under the revolving credit facility, such as availability reserves and borrowing base reserves, are customary for credit facilities of this type.
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     The revolving credit facility also includes various customary operating covenants, including restrictions on the incurrence and prepayment of other indebtedness, granting of liens, sales of assets, making of investments, maintenance of a minimum amount of inventory, and payment of dividends or other distributions. Failure to satisfy the covenants would constitute an event of default under the revolving credit facility. As of December 31, 2008, we were in compliance with all of the covenants.
     Our current credit ratings are as follows:
 	 	 	 	 	
 	 	Standard & Poor’s	 	Moody’s	
Corporate credit/family rating	 	B-	 	B3	
3.0% convertible senior notes	 	CCC	 	unrated	
Outlook	 	Negative	 	Negative	
     Our debt to total capitalization ratio was 37% at December 31, 2008 and 36% at December 31, 2007.
     Financial Markets and Defined Benefit Pension Plans
     In 2008, actual returns for our defined benefit pension plan assets were significantly below our expected long-term rate of return on plan assets of 8% due to adverse conditions in the financial markets. This performance and the associated decline in pension plan asset values did not impact our funding pattern with respect to these plans in 2008. A summary of actual plan funding in 2008 and expected funding in 2009 follows:
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Postretirement	
 	 	Defined Benefit	 	Health and Life	
 	 	Pension Plans	 	Benefit Plans	
 	 	(millions)	
Actual contributions in 2008	 	$	10.3	 	 	$	3.6	 	
Expected contributions in 2009	 	 	23.6	 	 	 	5.3	 	
     The amount we contribute to our pension plans is determined by IRS regulations, the Pension Protection Act of 2006, and government cost accounting standards.
     The valuation of benefit obligations and costs in our financial statements requires judgments and estimates including actuarial assumptions, expectations of future returns on benefit plan assets, and the estimated discount rate at which benefit obligations could be effectively settled. A change in any of these assumptions could result in different valuations. Our financial statements and future funding levels could be impacted to the extent actual results differ from these assumptions, or lead to changes in these assumptions. Refer to the risks, uncertainties and estimates related to pension plans in Item 1A, “Risk Factors”, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates,” and note 10 to our consolidated financial statements.
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     Financial Assurance and Related Liabilities
     The NRC requires that we guarantee the disposition of our depleted uranium and stored wastes with financial assurance. The financial assurance in place for depleted uranium and stored wastes is based on the quantity of depleted uranium and waste at the end of the prior year plus expected depleted uranium generated over the current year. We also provide financial assurance for the ultimate decontamination and decommissioning (“D&D”) of the American Centrifuge facilities to meet NRC and DOE requirements. Surety bonds for the disposition of depleted uranium and for D&D are partially collateralized by interest earning cash deposits included in other long-term assets. A summary of financial assurance, related liabilities and cash collateral follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Financial Assurance	 	 	Long-Term Liability	 	
 	 	December 31,	 	 	December 31,	 	
 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Depleted uranium disposition	 	$	232.0	 	 	$	188.3	 	 	$	119.5	 	 	$	98.3	 	
Decontamination and decommissioning of American Centrifuge	 	 	57.7	 	 	 	41.6	 	 	 	13.7	 	 	 	4.4	 	
Other financial assurance	 	 	22.9	 	 	 	16.5	 	 	 	 	 	 	 	 	 	

Total financial assurance	 	$	312.6	 	 	$	246.4	 	 	 	 	 	 	 	 	 	

Letters of credit	 	 	48.0	 	 	 	38.4	 	 	 	 	 	 	 	 	 	
Surety bonds	 	 	264.6	 	 	 	208.0	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash collateral deposit for surety bonds	 	$	135.1	 	 	$	97.0	 	 	 	 	 	 	 	 	 	
     The amount of financial assurance needed in the future for depleted uranium disposition is anticipated to increase by an estimated $35 to $45 million per year depending on Paducah GDP production volumes and the estimated unit disposition cost defined by the NRC requirement.
     The amount of financial assurance needed for D&D of the American Centrifuge Plant is anticipated to increase to roughly $200 million by the end of 2009, depending on construction progress and cost projections. The current estimate of the total cost related to NRC and DOE D&D requirements is $403 million. Financial assurance will also be required for the disposition of depleted uranium generated from future centrifuge operations.
     See note 15 to the consolidated financial statements for a more detailed explanation regarding the nature of differences between the financial assurance amounts and the related long-term liabilities.
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     Contractual Commitments
     USEC had contractual commitments at December 31, 2008, estimated as follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	2010-	 	 	2012-	 	 	 	 	 	 	 	
 	 	2009	 	 	2011	 	 	2013	 	 	Thereafter	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Financing (1):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Debt	 	$	95.7	 	 	$	—	 	 	$	—	 	 	$	575.0	 	 	$	670.7	 	
Interest on debt	 	 	20.5	 	 	 	34.5	 	 	 	34.5	 	 	 	17.3	 	 	 	106.8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	116.2	 	 	 	34.5	 	 	 	34.5	 	 	 	592.3	 	 	 	777.5	 	

Purchase Commitments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
United States Enrichment Corporation (2)	 	 	1,163.0	 	 	 	2,331.2	 	 	 	1,651.7	 	 	 	—	 	 	 	5,145.9	 	
American Centrifuge (3)	 	 	102.2	 	 	 	73.6	 	 	 	—	 	 	 	—	 	 	 	175.8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	1,265.2	 	 	 	2,404.8	 	 	 	1,651.7	 	 	 	—	 	 	 	5,321.7	 	

Expected payments on operating leases	 	 	6.7	 	 	 	11.1	 	 	 	6.8	 	 	 	29.2	 	 	 	53.8	 	
Other long-term liabilities (4)	 	 	29.5	 	 	 	54.7	 	 	 	81.1	 	 	 	436.2	 	 	 	601.5	 	

 	 	$	1,417.6	 	 	$	2,505.1	 	 	$	1,774.1	 	 	$	1,057.7	 	 	$	6,754.5	 	

 	 	 	
(1)	 	We paid the 6.750% senior notes balance of $95.7 million on the scheduled maturity date of January 20, 2009. The 3.0% convertible senior notes amounting to $575 million are due October 1, 2014, assuming no conversion to shares of common stock.	
 	 	 	
(2)	 	Purchase commitments of subsidiary United States Enrichment Corporation include a commitment to purchase SWU under the Russian Contract of approximately $3.4 billion and a commitment to purchase power under the TVA contract of approximately $1.7 billion.	
 	 	 	
 	 	Currently, prices under the Russian Contract are determined using a discount from an index of international and U.S. price points, including both long-term and spot prices. Beginning in 2010, subject to receipt of necessary governmental approvals, prices will be determined under a formula that combines a different mix of price points and other pricing elements. Under either formula, a multi-year retrospective view of market-based price points in the index is used to minimize the disruptive effect of any short-term swings in these price points. Actual amounts will vary based on changes in the price points and other pricing elements.	
 	 	 	
 	 	Capacity under the TVA power purchase agreement is fixed. Prices are subject to monthly fuel cost adjustments to reflect changes in TVA’s fuel costs, purchased power costs, and related costs.	
 	 	 	
(3)	 	Supply agreements for the purchase of materials, goods and services for the manufacture of centrifuge machines to be used in the American Centrifuge Plant. Prices for minimum purchase commitments above are subject to adjustment for inflation. Contractual provisions for termination payments total $26.7 million for these agreements.	
 	 	 	
(4)	 	Other long-term liabilities reported on the balance sheet include pension benefit obligations and postretirement health and life benefit obligations amounting to $391.2 million, accrued depleted uranium disposition costs of $119.5 million, the long-term portion of accrued lease turnover costs of $54.9 million and the liability for unrecognized tax benefits of $3.8 million.	
     Off-Balance Sheet Arrangements
     In December 2006, DOE signed an agreement with us licensing U.S. gas centrifuge technology to USEC for use in building new domestic uranium enrichment capacity. We will pay royalties to the U.S. government on annual revenues from sales of LEU produced in the American Centrifuge Plant. The royalty ranges from 1% to 2% of annual gross revenue from these sales. Payments are capped at $100 million over the life of the technology license. Other than the letters of credit issued under the credit facility, the surety bonds and certain contractual commitments discussed above, there were no material off-balance sheet arrangements, obligations, or other relationships at December 31, 2008 or 2007.
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Environmental Matters
     In addition to estimated costs for the future disposition of depleted uranium, we incur costs for matters relating to compliance with environmental laws and regulations, including the handling, treatment and disposal of hazardous, low-level radioactive and mixed wastes generated as a result of our operations. Environmental liabilities associated with GDP operations prior to July 28, 1998, are the responsibility of the U.S. government, except for liabilities relating to certain identified wastes generated by us and stored at the GDPs. DOE remains responsible for decontamination and decommissioning of the GDPs. Operating costs for environmental compliance, including estimated costs relating to the future disposition of depleted uranium, amounted to $39.9 million in 2008, $44.9 million in 2007, and $32.2 million in 2006.
     Under a cleanup agreement with the Environmental Protection Agency (“EPA”), we removed certain material from a site in South Carolina previously operated by Starmet CMI, one of our former contractors, that was attributable to quantities of depleted uranium we had sent there under a 1998 contract. In June 2007, we were contacted by the EPA concerning costs incurred by the EPA for additional cleanup at the Starmet site. In January 2009, pursuant to the terms of a September 2008 settlement agreement, we paid the EPA $1.0 million for the share of additional cleanup costs allocated to us in resolution of this matter. At this time, the EPA has completed its actions at the site, and we are not aware of any further claims associated with the site.
New Accounting Standards Not Yet Implemented
     In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements.” This statement clarifies the definition of fair value, establishes a framework for measuring fair value when required or permitted under other accounting pronouncements, and expands the disclosures on fair value measurements. The implementation of SFAS No. 157 for financial assets and liabilities, effective January 1, 2008, did not have an impact on USEC’s financial position and results of operations.
     SFAS No. 157 is effective beginning with USEC’s first quarter of 2009 for non-financial assets and liabilities. USEC does not expect that the adoption of the statement will have a material effect on its financial position or results of operations for the first quarter of 2009.
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk
     At December 31, 2008, the balance sheet carrying amounts for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and payables under the Russian Contract approximate fair value because of the short-term nature of the instruments.
     We have not entered into financial instruments for trading purposes. At December 31, 2008, the fair value of USEC’s term debt, based on the most recent trading price, and related balance sheet carrying amounts follow (in millions):
 	 	 	 	 	 	 	 	 	
 	 	Balance Sheet	 	 	Fair	 	
 	 	Carrying Amount	 	 	Value	 	
Debt:	 	 	 	 	 	 	 	 	
6.75% senior notes due January 20, 2009	 	$	95.7	 	 	$	94.9	 	
3.0% convertible senior notes due October 1, 2014	 	 	575.0	 	 	 	207.0	 	
 	 	 	 	 	 	 	
 	 	$	670.7	 	 	$	301.9	 	
 	 	 	 	 	 	 	
     Reference is made to additional information reported in management’s discussion and analysis of financial condition and results of operations included herein for quantitative and qualitative disclosures relating to:
 	•	 	commodity price risk for electric power requirements for the Paducah GDP (refer to “Overview — Cost of Sales” and “Results of Operations — Cost of Sales”),	
 	 	 	 	
 	•	 	commodity price risk for raw materials needed for construction of the American Centrifuge Plant, that could affect the overall cost of the project (refer to “Item 1A. Risk Factors — The cost of the American Centrifuge project will likely exceed the baseline project budget and increased costs and cost uncertainty could adversely affect our ability to finance and deploy the American Centrifuge Plant”), and	
 	 	 	 	
 	•	 	interest rate risk relating to any outstanding borrowings at variable interest rates under the $400.0 million revolving credit agreement (refer to “Liquidity and Capital Resources — Capital Structure and Financial Resources”).	
Item 8. Consolidated Financial Statements and Supplementary Data
     Our consolidated financial statements, together with related notes and the report of PricewaterhouseCoopers LLP, our independent registered public accounting firm, are set forth on the pages indicated in Part IV, Item 15.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
     None.
Item 9A. Controls and Procedures
     Disclosure Controls and Procedures
     USEC maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed by USEC in reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported on a timely basis and that such information is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
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     As of the end of the period covered by this report, USEC carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that disclosure controls and procedures were effective.
     Management’s Annual Report on Internal Control Over Financial Reporting
     USEC’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) and for an assessment of the effectiveness of internal control over financial reporting. USEC’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
     A company’s internal control over financial reporting includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
     Management assessed the effectiveness of USEC’s internal control over financial reporting as of December 31, 2008, based on criteria established in “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective at a reasonable assurance level as of December 31, 2008.
     The effectiveness of USEC’s internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
     Changes in Internal Control Over Financial Reporting
     There have not been any changes in internal control over financial reporting during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, USEC’s internal control over financial reporting.
Item 9B. Other Information
     None.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
     Certain information regarding executive officers is included in Part I of this annual report. Additional information concerning directors, executive officers and corporate governance is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 for the annual meeting of shareholders scheduled to be held on April 30, 2009.
Item 11. Executive Compensation
     Information concerning management compensation is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 for the annual meeting of shareholders scheduled to be held on April 30, 2009.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
     Information concerning security ownership of certain beneficial owners and management and related stockholder matters is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 for the annual meeting of shareholders scheduled to be held on April 30, 2009.
Item 13. Certain Relationships and Related Transactions, and Director Independence
     Information concerning certain relationships and related transactions and director independence is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 for the annual meeting of shareholders scheduled to be held on April 30, 2009.
Item 14. Principal Accountant Fees and Services
     Information concerning principal accountant fees and services is incorporated herein by reference to the definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 for the annual meeting of shareholders scheduled to be held on April 30, 2009.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) (1) Consolidated Financial Statements
Reference is made to the consolidated financial statements appearing elsewhere in this annual report.
(2) Financial Statement Schedules
No financial statement schedules are required to be filed as part of this annual report.
(3) Exhibits
The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report and such Exhibit Index is incorporated herein by reference. The accompanying Exhibit Index identifies each management contract or compensatory plan or arrangement required to be filed as an exhibit to this report, and such listing is incorporated herein by reference.
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SIGNATURES
     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 	 	 	 	 	
 	USEC Inc.
 	 	
February 26, 2009 	/s/ John K. Welch  	 	
 	John K. Welch 	 	
 	President and Chief Executive Officer 	 	
 	
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the date indicated.
 	 	 	 	 	
Signature	 	Title	 	Date	
 	 	 	 	 	
/s/ John K. Welch	 	President and Chief Executive Officer	 	February 26, 2009	
 	 	(Principal Executive Officer) and Director	 	 	
John K. Welch	 	 	 	 	
 	 	 	 	 	
/s/ John C. Barpoulis	 	Senior Vice President and Chief Financial	 	February 26, 2009	
 	 	Officer (Principal Financial Officer)	 	 	
John C. Barpoulis	 	 	 	 	
 	 	 	 	 	
/s/ J. Tracy Mey	 	Controller and Chief Accounting Officer	 	February 26, 2009	
 	 	(Principal Accounting Officer)	 	 	
J. Tracy Mey	 	 	 	 	
 	 	 	 	 	
/s/ James R. Mellor	 	Chairman of the Board	 	February 26, 2009	
 	 	 	 	 	
James R. Mellor	 	 	 	 	
 	 	 	 	 	
/s/ Michael H. Armacost	 	Director	 	February 26, 2009	
 	 	 	 	 	
Michael H. Armacost	 	 	 	 	
 	 	 	 	 	
/s/ Joyce F. Brown	 	Director	 	February 26, 2009	
 	 	 	 	 	
Joyce F. Brown	 	 	 	 	
 	 	 	 	 	
/s/ Joseph T. Doyle	 	Director	 	February 26, 2009	
 	 	 	 	 	
Joseph T. Doyle	 	 	 	 	
 	 	 	 	 	
/s/ H. William Habermeyer	 	Director	 	February 26, 2009	
 	 	 	 	 	
H. William Habermeyer	 	 	 	 	
 	 	 	 	 	
/s/ John R. Hall	 	Director	 	February 26, 2009	
 	 	 	 	 	
John R. Hall	 	 	 	 	
 	 	 	 	 	
/s/ William J. Madia	 	Director	 	February 26, 2009	
 	 	 	 	 	
William J. Madia	 	 	 	 	
 	 	 	 	 	
/s/ W. Henson Moore	 	Director	 	February 26, 2009	
 	 	 	 	 	
W. Henson Moore	 	 	 	 	
 	 	 	 	 	
/s/ Joseph F. Paquette, Jr.	 	Director	 	February 26, 2009	
 	 	 	 	 	
Joseph F. Paquette, Jr.	 	 	 	 	
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USEC Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	
 	 	Page	 	
Report of Independent Registered Public Accounting Firm	 	 	88	 	
Consolidated Balance Sheets	 	 	89	 	
Consolidated Statements of Income	 	 	90	 	
Consolidated Statements of Cash Flows	 	 	91	 	
Consolidated Statements of Stockholders’ Equity	 	 	92	 	
Notes to Consolidated Financial Statements	 	 	93 -- 125	 	
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Report of Independent Registered Public Accounting Firm
To Board of Directors and Stockholders of USEC Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, consolidated statements of cash flows, and consolidated statements of stockholders’ equity present fairly, in all material respects, the financial position of USEC Inc. and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in  Internal Control — Integrated Framework  issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 10 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans as of December 31, 2006. As discussed in Note 12 to the consolidated financial statements, the Company changed the manner in which it accounts for income taxes as of January 1, 2007.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
McLean, Virginia
February 24, 2009
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USEC Inc.
CONSOLIDATED BALANCE SHEETS
(millions, except share and per share data)
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
ASSETS	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	248.5	 	 	$	886.1	 	
Accounts receivable	 	 	154.1	 	 	 	252.9	 	
Inventories:	 	 	 	 	 	 	 	 	
Separative work units	 	 	813.0	 	 	 	677.3	 	
Uranium	 	 	402.1	 	 	 	465.9	 	
Materials and supplies	 	 	16.8	 	 	 	10.2	 	
 	 	 	 	 	 	 	
Total Inventories	 	 	1,231.9	 	 	 	1,153.4	 	
Deferred income taxes	 	 	67.9	 	 	 	49.5	 	
Other current assets	 	 	188.3	 	 	 	88.7	 	
 	 	 	 	 	 	 	
Total Current Assets	 	 	1,890.7	 	 	 	2,430.6	 	
Property, Plant and Equipment, net	 	 	736.1	 	 	 	292.2	 	
Other Long-Term Assets	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	273.3	 	 	 	180.1	 	
Deposit for surety bonds	 	 	135.1	 	 	 	97.0	 	
Pension asset	 	 	—	 	 	 	67.1	 	
Bond financing costs, net	 	 	12.0	 	 	 	13.8	 	
Goodwill	 	 	6.8	 	 	 	6.8	 	
Other long-term assets	 	 	1.3	 	 	 	0.2	 	
 	 	 	 	 	 	 	
Total Other Long-Term Assets	 	 	428.5	 	 	 	365.0	 	
 	 	 	 	 	 	 	
Total Assets	 	$	3,055.3	 	 	$	3,087.8	 	

LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	
Current portion of long-term debt	 	$	95.7	 	 	$	—	 	
Accounts payable and accrued liabilities	 	 	172.3	 	 	 	162.2	 	
Payables under Russian Contract	 	 	121.5	 	 	 	112.2	 	
Inventories owed to customers and suppliers	 	 	130.2	 	 	 	322.3	 	
Deferred revenue and advances from customers	 	 	196.7	 	 	 	119.1	 	
 	 	 	 	 	 	 	
Total Current Liabilities	 	 	716.4	 	 	 	715.8	 	
Long-Term Debt	 	 	575.0	 	 	 	725.0	 	
Other Long-Term Liabilities	 	 	 	 	 	 	 	 	
Depleted uranium disposition	 	 	119.5	 	 	 	98.3	 	
Postretirement health and life benefit obligations	 	 	168.1	 	 	 	130.6	 	
Pension benefit liabilities	 	 	223.1	 	 	 	23.0	 	
Other liabilities	 	 	90.8	 	 	 	85.6	 	
 	 	 	 	 	 	 	
Total Other Long-Term Liabilities	 	 	601.5	 	 	 	337.5	 	
Commitments and Contingencies (Note 16)	 	 	 	 	 	 	 	 	
Stockholders’ Equity	 	 	 	 	 	 	 	 	
Preferred stock, par value $1.00 per share, 25,000,000 shares authorized, none issued	 	 	—	 	 	 	—	 	
Common stock, par value $.10 per share, 250,000,000 shares authorized, 123,320,000 shares issued	 	 	12.3	 	 	 	12.3	 	
Excess of capital over par value	 	 	1,184.2	 	 	 	1,186.2	 	
Retained earnings	 	 	263.9	 	 	 	215.2	 	
Treasury stock, 11,564,000 and 12,741,000 shares	 	 	(84.1	)	 	 	(92.9	)	
Accumulated other comprehensive loss, net of tax	 	 	(213.9	)	 	 	(11.3	)	
 	 	 	 	 	 	 	
Total Stockholders’ Equity	 	 	1,162.4	 	 	 	1,309.5	 	
 	 	 	 	 	 	 	
Total Liabilities and Stockholders’ Equity	 	$	3,055.3	 	 	$	3,087.8	 	
 	 	 	 	 	 	 	
See notes to consolidated financial statements.
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USEC Inc.
CONSOLIDATED STATEMENTS OF INCOME
(millions, except per share data)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
Revenue:	 	 	 	 	 	 	 	 	 	 	 	 	
Separative work units	 	$	1,175.5	 	 	$	1,570.5	 	 	$	1,337.4	 	
Uranium	 	 	217.1	 	 	 	163.5	 	 	 	316.7	 	
U.S. government contracts and other 	 	 	222.0	 	 	 	194.0	 	 	 	194.5	 	
 	 	 	 	 	 	 	 	 	 	
Total revenue	 	 	1,614.6	 	 	 	1,928.0	 	 	 	1,848.6	 	

Cost of sales:	 	 	 	 	 	 	 	 	 	 	 	 	
Separative work units and uranium	 	 	1,202.2	 	 	 	1,473.6	 	 	 	1,349.2	 	
U.S. government contracts and other	 	 	183.6	 	 	 	166.9	 	 	 	162.5	 	
 	 	 	 	 	 	 	 	 	 	
Total cost of sales	 	 	1,385.8	 	 	 	1,640.5	 	 	 	1,511.7	 	
 	 	 	 	 	 	 	 	 	 	
Gross profit	 	 	228.8	 	 	 	287.5	 	 	 	336.9	 	
Special charges	 	 	—	 	 	 	—	 	 	 	3.9	 	
Advanced technology costs	 	 	110.2	 	 	 	127.3	 	 	 	105.5	 	
Selling, general and administrative	 	 	54.3	 	 	 	45.3	 	 	 	48.8	 	
 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	64.3	 	 	 	114.9	 	 	 	178.7	 	
Interest expense	 	 	17.3	 	 	 	16.9	 	 	 	14.5	 	
Interest (income)	 	 	(24.7	)	 	 	(33.8	)	 	 	(6.2	)	
 	 	 	 	 	 	 	 	 	 	
Income before income taxes	 	 	71.7	 	 	 	131.8	 	 	 	170.4	 	
Provision for income taxes	 	 	23.0	 	 	 	35.2	 	 	 	64.2	 	
 	 	 	 	 	 	 	 	 	 	
Net income	 	$	48.7	 	 	$	96.6	 	 	$	106.2	 	
 	 	 	 	 	 	 	 	 	 	
Net income per share — basic	 	$	.44	 	 	$	1.04	 	 	$	1.22	 	
Net income per share — diluted	 	$	.35	 	 	$	.94	 	 	$	1.22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of shares outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	110.6	 	 	 	93.0	 	 	 	86.6	 	
Diluted	 	 	158.7	 	 	 	105.8	 	 	 	86.8	 	
See notes to consolidated financial statements.
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USEC Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(millions)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
Cash Flows From Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	48.7	 	 	$	96.6	 	 	$	106.2	 	
Adjustments to reconcile net income to net cash provided by (used in) operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation and amortization	 	 	34.2	 	 	 	39.5	 	 	 	36.7	 	
Deferred income taxes	 	 	3.1	 	 	 	(40.6	)	 	 	(13.4	)	
Impairment of intangible asset	 	 	—	 	 	 	—	 	 	 	2.6	 	
Changes in operating assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable — (increase) decrease	 	 	98.8	 	 	 	(37.0	)	 	 	40.8	 	
Inventories — net (increase) decrease	 	 	(270.6	)	 	 	36.2	 	 	 	176.1	 	
Payables under Russian Contract — increase (decrease)	 	 	9.3	 	 	 	6.9	 	 	 	(6.3	)	
Deferred revenue, net of deferred costs — increase (decrease)	 	 	24.5	 	 	 	5.1	 	 	 	(3.7	)	
Accrued depleted uranium disposition	 	 	21.2	 	 	 	26.8	 	 	 	24.5	 	
Accounts payable and other liabilities — (decrease)	 	 	(31.2	)	 	 	(25.1	)	 	 	(82.1	)	
Other, net	 	 	(42.9	)	 	 	0.8	 	 	 	(3.3	)	
 	 	 	 	 	 	 	 	 	 	
Net Cash Provided by (Used in) Operating Activities	 	 	(104.9	)	 	 	109.2	 	 	 	278.1	 	

Cash Flows Used in Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(441.9	)	 	 	(137.2	)	 	 	(44.8	)	
Deposits for surety bonds	 	 	(35.3	)	 	 	(33.2	)	 	 	(34.8	)	
 	 	 	 	 	 	 	 	 	 	
Net Cash (Used in) Investing Activities	 	 	(477.2	)	 	 	(170.4	)	 	 	(79.6	)	

Cash Flows Provided by (Used in) Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	
Borrowings under credit facility	 	 	48.3	 	 	 	75.1	 	 	 	133.8	 	
Repayments under credit facility	 	 	(48.3	)	 	 	(75.1	)	 	 	(133.8	)	
Repayment and repurchases of senior notes, including premiums	 	 	(54.3	)	 	 	—	 	 	 	(288.8	)	
Tax benefit related to stock-based compensation	 	 	—	 	 	 	0.9	 	 	 	0.4	 	
Proceeds from issuance of convertible senior notes	 	 	—	 	 	 	575.0	 	 	 	—	 	
Payments made for deferred financing costs	 	 	(1.3	)	 	 	(14.3	)	 	 	(0.3	)	
Common stock issued, net of issuance costs	 	 	0.1	 	 	 	214.3	 	 	 	2.5	 	
 	 	 	 	 	 	 	 	 	 	
Net Cash Provided by (Used in) Financing Activities	 	 	(55.5	)	 	 	775.9	 	 	 	(286.2	)	
 	 	 	 	 	 	 	 	 	 	
Net Increase (Decrease)	 	 	(637.6	)	 	 	714.7	 	 	 	(87.7	)	
Cash and Cash Equivalents at Beginning of Period	 	 	886.1	 	 	 	171.4	 	 	 	259.1	 	
 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents at End of Period	 	$	248.5	 	 	$	886.1	 	 	$	171.4	 	

Supplemental Cash Flow Information	 	 	 	 	 	 	 	 	 	 	 	 	
Interest paid, net of capitalized interest	 	$	15.9	 	 	$	6.9	 	 	$	19.3	 	
Income taxes paid	 	 	50.0	 	 	 	101.9	 	 	 	107.3	 	
See notes to consolidated financial statements.
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USEC Inc.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(millions, except per share data)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Common	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	 	 	 	
 	 	Stock,	 	 	Excess of	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Other	 	 	 	 	 	 	 	
 	 	Par Value	 	 	Capital	 	 	 	 	 	 	 	 	 	 	Deferred	 	 	Compre-	 	 	Total	 	 	Compre-	 	
 	 	$.10 per	 	 	over	 	 	Retained	 	 	Treasury	 	 	Comp-	 	 	hensive	 	 	Stockholders'	 	 	hensive	 	
 	 	Share	 	 	Par Value	 	 	Earnings	 	 	Stock	 	 	ensation	 	 	Income (Loss)	 	 	Equity	 	 	Income (Loss)	 	
Balance at December 31, 2005	 	 	10.0	 	 	 	970.6	 	 	 	31.3	 	 	 	(99.5	)	 	 	(2.7	)	 	 	(2.1	)	 	 	907.6	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common stock issued:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from exercise of stock options	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2.1	 	 	 	—	 	 	 	—	 	 	 	2.1	 	 	 	—	 	
Restricted and other stock issued, net of amortization	 	 	—	 	 	 	2.7	 	 	 	—	 	 	 	1.9	 	 	 	—	 	 	 	—	 	 	 	4.6	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Eliminate deferred compensation under SFAS No. 123(R)	 	 	—	 	 	 	(2.7	)	 	 	—	 	 	 	—	 	 	 	2.7	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reduction in minimum pension liability, net of income tax of $0.5 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1.1	 	 	 	1.1	 	 	 	1.1	 	
Recognition of funding status of retirement plans under SFAS No. 158, net of income tax benefit of $26.9 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(35.6	)	 	 	(35.6	)	 	 	—	 	
Net income	 	 	—	 	 	 	—	 	 	 	106.2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	106.2	 	 	 	106.2	 	

Balance at December 31, 2006	 	 	10.0	 	 	 	970.6	 	 	 	137.5	 	 	 	(95.5	)	 	 	—	 	 	 	(36.6	)	 	 	986.0	 	 	$	107.3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Implementation of FIN 48, net of income tax benefit of $7.5 million (Note 12)	 	 	—	 	 	 	—	 	 	 	(18.9	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(18.9	)	 	 	—	 	
Common stock issued:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from issuance of common stock	 	 	2.3	 	 	 	211.5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	213.8	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from exercise of stock options	 	 	—	 	 	 	—	 	 	 	—	 	 	 	0.8	 	 	 	—	 	 	 	—	 	 	 	0.8	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted and other stock issued, net of amortization	 	 	—	 	 	 	4.1	 	 	 	—	 	 	 	1.8	 	 	 	—	 	 	 	—	 	 	 	5.9	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Amortization of actuarial losses and prior service costs (credits) and valuation revisions, net of income tax of $14.8 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	25.3	 	 	 	25.3	 	 	 	25.3	 	
Net income	 	 	—	 	 	 	—	 	 	 	96.6	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	96.6	 	 	 	96.6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2007	 	 	12.3	 	 	 	1,186.2	 	 	 	215.2	 	 	 	(92.9	)	 	 	—	 	 	 	(11.3	)	 	 	1,309.5	 	 	$	121.9	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted and other common stock issued, net of amortization	 	 	—	 	 	 	(2.0	)	 	 	—	 	 	 	8.8	 	 	 	—	 	 	 	—	 	 	 	6.8	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Valuation revisions and amortization of actuarial losses and prior service costs (credits), net of income tax of $114.7 million	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(202.6	)	 	 	(202.6	)	 	 	(202.6	)	
Net income	 	 	—	 	 	 	—	 	 	 	48.7	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	48.7	 	 	 	48.7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2008	 	$	12.3	 	 	$	1,184.2	 	 	$	263.9	 	 	$	(84.1	)	 	$	—	 	 	$	(213.9	)	 	$	1,162.4	 	 	$	(153.9	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See notes to consolidated financial statements.
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USEC Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
     USEC Inc. (“USEC”) is a global energy company and is a leading supplier of low enriched uranium (“LEU”) for commercial nuclear power plants.
     Customers typically provide uranium to us as part of their enrichment contracts. Customers are billed for the separative work units (“SWU”) deemed to be contained in the LEU delivered to them. SWU is a standard unit of measurement that represents the effort required to transform a given amount of uranium into two streams: enriched uranium having a higher percentage of U 235  and depleted uranium having a lower percentage of U 235 . The SWU contained in LEU is calculated using an industry standard formula based on the physics of enrichment.
Consolidation
     The consolidated financial statements include the accounts of USEC Inc., its principal subsidiary, United States Enrichment Corporation, and its other subsidiaries including NAC International Inc. (“NAC”). All material intercompany transactions are eliminated. Certain amounts in the notes to the consolidated financial statements have been reclassified to conform with the current presentation.
Cash and Cash Equivalents
     Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Inventories
     Inventories of SWU and uranium are valued at the lower of cost or market. Market is based on the terms of long-term contracts with customers, and, for uranium not under contract, market is based primarily on published long-term price indicators at the balance sheet date. SWU and uranium inventory costs are determined using the monthly moving average cost method.
     SWU costs are based on production costs at the plants and purchase costs under the Russian Contract. Production costs consist principally of electric power, labor and benefits, depleted uranium disposition cost estimates, materials, depreciation and amortization and maintenance and repairs. The cost of the SWU component of LEU purchased under the Russian Contract is recorded at acquisition cost plus related shipping costs.
     Underfeeding is a mode of operation that uses or feeds less uranium but requires more SWU in the enrichment process, which requires more electric power. The quantity of uranium that is earned or added to uranium inventory from underfeeding is accounted for as a byproduct of the enrichment process. Production costs are allocated to the uranium earned based on the net realizable value of the uranium, and the remainder of production costs is allocated to SWU inventory costs.
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Revenue
     Revenue is derived from sales of the SWU component of LEU, from sales of both the SWU and uranium components of LEU, and from sales of uranium. Revenue is recognized at the time LEU or uranium is delivered under the terms of contracts with domestic and international electric utility customers. USEC often advance ships LEU to nuclear fuel fabricators for scheduled or anticipated orders from utility customers. Based on customer orders, USEC generally arranges for the transfer of title of LEU from USEC to the customer for the specified quantity of LEU at the fuel fabricator. Revenue is recognized when delivery of LEU to the customer occurs at the fuel fabricator. Some customers take title and delivery of LEU at the Paducah plant, and revenue is recognized when delivery of LEU to the customer is complete.
     Certain customers make advance payments to be applied against future orders or deliveries. Advances from customers are reported as deferred revenue, and revenue is recognized as LEU is delivered. Under SWU barter contracts, USEC exchanges SWU for uranium. Revenue from the sale of SWU under barter contracts is recognized at the time LEU is delivered and is based on the fair market value of the uranium received in exchange for SWU. There was no revenue from SWU barter contracts in 2008. Revenue from SWU barter contracts was $50.8 million in 2007 and $12.5 million in 2006.
     USEC performs contract work primarily for the U.S. Department of Energy (“DOE”) and DOE contractors. U.S. government contract revenue includes billings for fees and reimbursements for allowable costs that are determined in accordance with the terms of the underlying contracts. USEC records revenue as work is performed and as fees are earned. Revenues determined based on allowable costs include pension and other allocated costs that are determined in accordance with government cost accounting standards, whereas costs and expenses reflected in the financial statements are determined in accordance with generally accepted accounting principles. Amounts representing contract change orders or final billing rates based on incurred costs are accrued and included in revenue when they can be reliably estimated and realization is probable. The final settlement of the allowable costs submitted for reimbursement is subject to audit by the Defense Contract Audit Agency (“DCAA”) and acceptance by DOE. This process has been completed for fiscal 2002, USEC’s first year as a federal contractor under government cost accounting standards. In addition, as of December 31, 2008, USEC has finalized and submitted to DOE the billable incurred costs for contract work for the six months ended December 31, 2002 and the years ended December 31, 2003, 2004, 2005, 2006, and 2007. Based on USEC’s limited experience to date, revenue resulting from final billing rates is recognized upon completion of the DCAA audit and notice by DOE authorizing final billing.
Advanced Technology Costs
     Costs relating to the American Centrifuge technology are charged to expense or capitalized based on the nature of the activities and estimates and judgments involving the completion of project milestones. Costs relating to the demonstration of American Centrifuge technology are charged to expense as incurred. Demonstration costs include Nuclear Regulatory Commission (“NRC”) licensing of the American Centrifuge Demonstration Facility in Piketon, Ohio, engineering activities, and assembling and testing of centrifuge machines and equipment at centrifuge test facilities located in Oak Ridge, Tennessee and at the American Centrifuge Demonstration Facility.
     Capitalized costs relating to the American Centrifuge technology include NRC licensing of the American Centrifuge Plant in Piketon, Ohio, engineering activities, construction of centrifuge machines and equipment, leasehold improvements and other costs directly associated with the commercial plant. Capitalized centrifuge costs are recorded in property, plant and equipment as part of construction work in progress. Amounts capitalized include interest of $14.7 million in 2008, $6.3 million in 2007 and $3.1 million in 2006. The continued capitalization of costs is subject to ongoing review and successful project completion. USEC’s move during the second half of 2007 from a demonstration phase to a commercial plant phase in which significant expenditures are capitalized was based on management’s judgment that the technology has a high probability of commercial success and meets internal targets related to physical control, technical achievement and economic viability. If conditions change and deployment were no longer probable, costs that were previously capitalized would be charged to expense.
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     In 2002, USEC and DOE signed an agreement in which both USEC and DOE made long-term commitments directed at resolving issues related to the stability and security of the domestic uranium enrichment industry. Discussion of USEC’s commitments related to American Centrifuge project milestones under this agreement is provided in note 16.
Property, Plant and Equipment
     Construction work in progress is recorded at acquisition or construction cost. Upon being placed into service, costs are transferred to leasehold improvements or machinery and equipment at which time depreciation and amortization commences.
     USEC leases the Paducah gaseous diffusion plant (“GDP”) located in Paducah, Kentucky and the Portsmouth GDP located in Piketon, Ohio from DOE. Leasehold improvements and machinery and equipment are recorded at acquisition cost and depreciated on a straight line basis over the shorter of the useful life of the assets or the expected productive life of the plant, which is 2016 for the Paducah GDP commensurate with an extension of the lease agreement exercised in June 2008. Maintenance and repair costs are charged to production costs as incurred.
Lease Turnover Costs and Asset Retirement Obligations
     Property, plant and equipment assets related to the GDPs are not subject to an asset retirement obligation. At the end of the lease, ownership of plant and equipment that USEC leaves at the GDPs transfers to DOE, and responsibility for decontamination and decommissioning of the GDPs remains with DOE. USEC estimates and accrues lease turnover costs. For the operating Paducah GDP, the balance of expected costs is being accrued over the expected productive life of the plant. Costs of returning the GDPs to DOE in acceptable condition include removing uranium deposits as required and removing USEC-generated waste. Liabilities for lease turnover costs are based on current-dollar cost estimates and are not discounted.
     USEC also leases facilities in Piketon, Ohio from DOE for the American Centrifuge Plant. USEC owns all capital improvements and, unless otherwise consented to by DOE, must remove them by the conclusion of the lease term. At the conclusion of the 36-year lease period in 2043, assuming no further extensions, USEC is obligated to return these leased facilities to DOE in a condition that meets NRC requirements and in the same condition as the facilities were in when they were leased to USEC (other than due to normal wear and tear).
     Decontamination and decommissioning requirements for the American Centrifuge Plant create an asset retirement obligation. As construction of the American Centrifuge Plant takes place, the present value of the related asset retirement obligation is recognized as a liability. An equivalent amount is recognized as part of the capitalized asset cost. The liability is accreted, or increased, over time for the time value of money. The accretion is charged to cost of sales in the LEU segment. Upon commencement of commercial operations, the asset cost will be depreciated over the shorter of the asset life or the expected lease period.
     During each reporting period, USEC reassesses and revises the estimate of the asset retirement obligation based on construction progress, cost evaluation of future decommissioning expectations, and other judgmental considerations which impact the amount recorded in both construction work in progress and other long-term liabilities.
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Long-Lived Assets
     USEC evaluates the carrying value of long-lived assets by performing impairment tests whenever adverse conditions or changes in circumstances indicate a possible impairment loss. Impairment tests are based on a comparison of estimated future cash flows to the carrying values of long-lived assets. If impairment is indicated, the asset carrying value is reduced to fair market value or, if fair market value is not readily available, the asset is reduced to a value determined by applying a discount rate to expected cash flows.
Environmental Costs
     Environmental costs relating to operations are accrued and charged to inventory costs as incurred. Estimated environmental costs, including depleted uranium disposition and waste disposal, are accrued where environmental assessments indicate that storage, treatment or disposal is probable and costs can be reasonably estimated. USEC stores depleted uranium at the Paducah and Portsmouth GDPs for future disposition. Changes in the estimated unit disposal cost result in charges to cost of sales for the accumulated quantity of depleted uranium. Liabilities for waste and depleted uranium disposition are based on current-dollar cost estimates and are not discounted.
Financial Instruments
     The balance sheet carrying amounts for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and payables under the Russian Contract approximate fair value because of the short-term nature of the instruments.
Concentrations of Credit Risk
     Credit risk could result from the possibility of a customer failing to perform or pay according to the terms of a contract. Extension of credit is based on an evaluation of each customer’s financial condition. USEC regularly monitors credit risk exposure and takes steps to mitigate the likelihood of such exposure resulting in a loss.
Stock-Based Compensation
     USEC has stock-based compensation plans available to grant restricted stock, restricted stock units, non-qualified stock options, performance awards and other stock-based awards to key employees and non-employee directors, as well as an employee stock purchase plan. Stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized over the requisite service period, which is either immediate recognition if the employee is eligible to retire, or on a straight-line basis until the earlier of either the date of retirement eligibility or the end of the vesting period.
Deferred Income Taxes
     USEC follows the asset and liability approach to account for deferred income taxes. Deferred tax assets and liabilities are recognized for the anticipated future tax consequences of temporary differences between the balance sheet carrying amounts of assets and liabilities and their respective tax bases. Deferred income taxes are based on income tax rates in effect for the years in which temporary differences are expected to reverse. The effect on deferred income taxes of a change in income tax rates is recognized in income when the change in rates is enacted in the law. A valuation allowance is provided if it is more likely than not that some or all of the deferred tax assets may not be realized.
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Use of Estimates
     The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported amounts presented and disclosed in the consolidated financial statements. Significant estimates and judgments include, but are not limited to, pension and postretirement health and life benefit costs and obligations, costs for the conversion, transportation and disposition of depleted uranium, accounting treatment for expenditures on American Centrifuge, plant lease turnover costs, the tax bases of assets and liabilities, the future recoverability of deferred tax assets, and determination of the valuation allowance for deferred tax assets. Actual results may differ from such estimates, and estimates may change if the underlying conditions or assumptions change.
New Accounting Standard
     In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements.” This statement clarifies the definition of fair value, establishes a framework for measuring fair value when required or permitted under other accounting pronouncements, and expands the disclosures on fair value measurements. The implementation of SFAS No. 157 for financial assets and liabilities, effective January 1, 2008, did not have an impact on USEC’s financial position and results of operations.
     SFAS No. 157 is effective beginning with USEC’s first quarter of 2009 for non-financial assets and liabilities. USEC does not expect that the adoption of the statement will have a material effect on its financial position or results of operations for the first quarter of 2009.
2. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
 	 	(millions)	 	
Accounts receivable (1):	 	 	 	 	 	 	 	 	
Utility customers:	 	 	 	 	 	 	 	 	
Trade receivables	 	$	109.2	 	 	$	160.9	 	
Unbilled revenue (2)	 	 	1.5	 	 	 	53.3	 	
 	 	 	 	 	 	 	
 	 	 	110.7	 	 	 	214.2	 	

Contract services, primarily Department of Energy (3):	 	 	 	 	 	 	 	 	
Billed revenue	 	 	26.6	 	 	 	24.9	 	
Unbilled revenue	 	 	16.8	 	 	 	13.8	 	
 	 	 	 	 	 	 	
 	 	 	43.4	 	 	 	38.7	 	
 	 	 	 	 	 	 	
 	 	$	154.1	 	 	$	252.9	 	

Other current assets:	 	 	 	 	 	 	 	 	
Deferred costs relating to deferred revenue	 	$	111.4	 	 	$	58.3	 	
Prepaid items	 	 	76.9	 	 	 	30.4	 	
 	 	 	 	 	 	 	
 	 	$	188.3	 	 	$	88.7	 	

 	 	 	
(1)	 	Accounts receivable are net of valuation and allowances for doubtful accounts totaling $14.5 million at December 31, 2008 and $17.4 million at December 31, 2007.	
 	 	 	
(2)	 	Unbilled revenue for utility customers represents price adjustments for past deliveries that are not yet billable under the applicable contracts.	
 	 	 	
(3)	 	Billings for contract services related to DOE are invoiced based on provisional billing rates approved by DOE. Unbilled revenue represents the difference between actual costs incurred, prior to DCAA audit and notice by DOE authorizing final billing, and provisional billing rate invoiced amounts. USEC expects to invoice and collect the unbilled amounts as billing rates are revised, submitted to and approved by DOE.	
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3. PURCHASE OF SEPARATIVE WORK UNITS UNDER RUSSIAN CONTRACT
     USEC is the U.S. government’s exclusive executive agent (“Executive Agent”) in connection with a government-to-government nonproliferation agreement between the United States and the Russian Federation. Under the agreement, USEC has been designated by the U.S. government to order LEU derived from dismantled Soviet nuclear weapons. In January 1994, USEC signed a commercial agreement (“Russian Contract”) with a Russian government entity known as OAO Techsnabexport (“TENEX”), to implement the program.
     USEC has agreed to purchase approximately 5.5 million SWU each calendar year for the remaining term of the Russian Contract through 2013. Over the life of the 20-year Russian Contract, USEC expects to purchase about 92 million SWU contained in LEU derived from 500 metric tons of highly enriched uranium, and as of December 31, 2008, USEC had purchased 65 million SWU contained in LEU derived from 352 metric tons of highly enriched uranium. Purchases under the Russian Contract approximate one-half of USEC’s supply mix. Prices are determined using a discount from an index of international and U.S. price points, including both long-term and spot prices. A multi-year retrospective view of the index is used to minimize the disruptive effect of any short-term market price swings. Increases in these price points in recent years have resulted in increases to the index used to determine prices under the Russian Contract. On February 13, 2009, USEC entered into an amendment to the Russian Contract to revise the pricing methodology for delivery in calendar years 2010 through 2013. Approval of both the U.S. government and the government of the Russian Federation is required for the amendment to become effective. The new pricing methodology is intended to enhance the stability of future pricing for both parties through a formula that combines a different mix of price points and other pricing elements.
     The Russian Contract provides that the parties may agree on appropriate adjustments, if necessary, to ensure that TENEX receives at least approximately $7.6 billion for the SWU component over the 20-year term of the Russian Contract through 2013. From inception of the Russian Contract in 1994 through December 31, 2008, USEC has purchased the SWU component of LEU at an aggregate cost of approximately $5.6 billion. Purchases of SWU under the Russian Contract are expected to exceed $0.5 billion per year through 2013.
4. INVENTORIES
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
 	 	(millions)	 	
Current assets:	 	 	 	 	 	 	 	 	
Separative work units	 	$	813.0	 	 	$	677.3	 	
Uranium	 	 	402.1	 	 	 	465.9	 	
Materials and supplies	 	 	16.8	 	 	 	10.2	 	
 	 	 	 	 	 	 	
 	 	 	1,231.9	 	 	 	1,153.4	 	
 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	
Inventories owed to customers and suppliers	 	 	(130.2	)	 	 	(322.3	)	
 	 	 	 	 	 	 	
Inventories, net	 	$	1,101.7	 	 	$	831.1	 	
 	 	 	 	 	 	 	
Inventories Owed to Customers and Suppliers
     Generally, title to uranium provided by customers as part of their enrichment contracts does not pass to USEC until delivery of LEU. In limited cases, however, title to the uranium passes to USEC immediately upon delivery of the uranium by the customer. Uranium provided by customers for which title passed to USEC is recorded on the balance sheet at estimated fair values of $1.6 million at December 31, 2008 and $2.8 million at December 31, 2007.
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     Additionally, USEC owed SWU and uranium inventories to fabricators with a cost totaling $128.6 million at December 31, 2008 and $319.5 million at December 31, 2007. Fabricators process LEU into fuel for use in nuclear reactors. Under inventory optimization arrangements between USEC and domestic fabricators, fabricators order bulk quantities of LEU from USEC based on scheduled or anticipated orders from utility customers for deliveries in future periods. As delivery obligations under actual customer orders arise, USEC satisfies these obligations by arranging for the transfer to the customer of title to the specified quantity of LEU on the fabricator’s books. Fabricators have other inventory supplies and, where a fabricator has elected to order less material from USEC than USEC is required to deliver to its customers at the fabricator, the fabricator will use these other inventories to satisfy USEC’s customer order obligations on USEC’s behalf. In such cases, the transfer of title of LEU from USEC to the customer results in quantities of SWU and uranium owed by USEC to the fabricator. The amounts of SWU and uranium owed to fabricators are satisfied as future bulk deliveries of LEU are made.
Uranium Provided by Customers and Suppliers
     USEC held uranium with estimated fair values of approximately $3.8 billion at December 31, 2008, and $5.8 billion at December 31, 2007, to which title was held by customers and suppliers and for which no assets or liabilities were recorded on the balance sheet. The reduction reflects a 42% decline in the uranium spot price indicator partially offset by a 12% increase in quantities. Utility customers provide uranium to USEC as part of their enrichment contracts. Generally, title to uranium provided by customers remains with the customer until delivery of LEU at which time title to LEU is transferred to the customer, and title to uranium is transferred to USEC.
5. PROPERTY, PLANT AND EQUIPMENT
     A summary of changes in property, plant and equipment follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	Transfers	 	 	 	 	 	 	 	 	 	Transfers	 	 	 	 	
 	 	December 31,	 	 	Capital Expenditures	 	 	and	 	 	December 31,	 	 	Capital Expenditures	 	 	and	 	 	December 31,	 	
 	 	2005	 	 	(Depreciation)	 	 	Retirements	 	 	2006	 	 	(Depreciation)	 	 	Retirements	 	 	2007	 	
Construction work in progress	 	$	29.0	 	 	$	53.9	 	 	$	(11.1	)	 	$	71.8	 	 	$	141.5	 	 	$	(20.6	)	 	$	192.7	 	
Leasehold improvements	 	 	161.5	 	 	 	—	 	 	 	6.5	 	 	 	168.0	 	 	 	—	 	 	 	3.8	 	 	 	171.8	 	
Machinery and equipment	 	 	179.7	 	 	 	1.2	 	 	 	1.1	 	 	 	182.0	 	 	 	2.7	 	 	 	6.3	 	 	 	191.0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	370.2	 	 	 	55.1	 	 	 	(3.5	)	 	 	421.8	 	 	 	144.2	 	 	 	(10.5	)	 	 	555.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated depreciation and amortization	 	 	(199.0	)	 	 	(36.3	)	 	 	3.4	 	 	 	(231.9	)	 	 	(37.4	)	 	 	6.0	 	 	 	(263.3	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	171.2	 	 	$	18.8	 	 	$	(0.1	)	 	$	189.9	 	 	$	106.8	 	 	$	(4.5	)	 	$	292.2	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Transfers	 	 	 	 	
 	 	December 31,	 	 	Capital Expenditures	 	 	and	 	 	December 31,	 	
 	 	2007	 	 	(Depreciation)	 	 	Retirements	 	 	2008	 	
Construction work in progress	 	$	192.7	 	 	$	472.5	 	 	$	(47.7	)	 	$	617.5	 	
Leasehold improvements	 	 	171.8	 	 	 	—	 	 	 	5.0	 	 	 	176.8	 	
Machinery and equipment	 	 	191.0	 	 	 	2.1	 	 	 	41.2	 	 	 	234.3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	555.5	 	 	 	474.6	 	 	 	(1.5	)	 	 	1,028.6	 	
Accumulated depreciation and amortization	 	 	(263.3	)	 	 	(30.7	)	 	 	1.5	 	 	 	(292.5	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	292.2	 	 	$	443.9	 	 	$	—	 	 	$	736.1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     Capital expenditures include items in accounts payable and accrued liabilities for which cash is paid in the following period.
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     USEC is working to construct and deploy the American Centrifuge Plant. Construction work in progress related to the American Centrifuge Plant, none of which has yet been placed in service, totaled $601.8 million at December 31, 2008 and $181.8 million at December 31, 2007. Capitalized asset retirement obligations included in construction work in progress totaled $13.0 million at December 31, 2008 and $4.3 million at December 31, 2007.
6. GOODWILL AND INTANGIBLES
     USEC acquired NAC in 2004, allocating $7.5 million of the purchase cost to goodwill and $3.9 million to intangible assets related to customer contracts and relationships. As part of the acquisition, a tax-related valuation allowance of $2.3 million was established primarily for state net operating losses that are available to offset future taxable income of NAC. During 2006, USEC recognized $0.7 million of tax benefits earned or expected to be earned from the net operating losses. The offset to these benefits was recorded as a reduction to goodwill. The goodwill amount is not deductible for income tax purposes.
     The amount allocated to intangible assets included $3.4 million related to the management of the Nuclear Materials Management and Safeguards System (“NMMSS”) for DOE. This value was based on a three-year, $25 million contract extension that ran through September 2008, and further renewals that were anticipated through 2017. In 2006, DOE verbally communicated to NAC that the NMMSS contract would be set aside for a small business after the contract expired in 2008, and DOE issued a solicitation seeking qualified small businesses with an interest to bid. A special charge of $2.6 million in 2006 represents an impairment of the intangible asset since NAC was not considered a qualified small business as defined by DOE. The special charge was calculated after analyzing cash flow projections and comparing the results to the estimated fair value of the assets acquired at the date of acquisition. Amortization of the remaining portion of intangible assets relating to NMMSS was completed in 2008.
     Intangible assets related to NAC’s customer contracts and relationships reflect the special charge and amortization as follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Gross Carrying	 	 	Accumulated	 	 	 	 	
 	 	Amount	 	 	Amortization	 	 	Net	 	
December 31, 2005	 	$	3.9	 	 	$	(0.3	)	 	$	3.6	 	
2006 amortization expense and special charge	 	 	(2.6	)	 	 	(0.4	)	 	 	(3.0	)	
 	 	 	 	 	 	 	 	 	 	
December 31, 2006	 	 	1.3	 	 	 	(0.7	)	 	 	0.6	 	
2007 amortization expense	 	 	—	 	 	 	(0.4	)	 	 	(0.4	)	
 	 	 	 	 	 	 	 	 	 	
December 31, 2007	 	 	1.3	 	 	 	(1.1	)	 	 	0.2	 	
2008 amortization expense	 	 	—	 	 	 	(0.2	)	 	 	(0.2	)	
 	 	 	 	 	 	 	 	 	 	
December 31, 2008	 	$	1.3	 	 	$	(1.3	)	 	$	-	 	
 	 	 	 	 	 	 	 	 	 	
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7. ACCOUNTS PAYABLE AND ACCRUED LIABILITES
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
 	 	(millions)	 	
Trade payables	 	$	36.6	 	 	$	47.3	 	
Compensation and benefits	 	 	53.3	 	 	 	49.5	 	
Accrued interest payable on long-term debt	 	 	7.9	 	 	 	9.6	 	
Accrued income taxes payable	 	 	1.9	 	 	 	4.2	 	
American Centrifuge accrued liabilities	 	 	48.5	 	 	 	15.5	 	
Other accrued liabilities	 	 	24.1	 	 	 	36.1	 	
 	 	 	 	 	 	 	
 	 	$	172.3	 	 	$	162.2	 	
 	 	 	 	 	 	 	
8. DEFERRED REVENUE AND ADVANCES FROM CUSTOMERS
     Deferred revenue and advances from customers were as follows (in millions):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
Deferred revenue	 	$	196.3	 	 	$	116.4	 	
Advances from customers	 	 	0.4	 	 	 	2.7	 	
 	 	 	 	 	 	 	
 	 	$	196.7	 	 	$	119.1	 	
 	 	 	 	 	 	 	
     In a number of sales transactions, title to uranium or LEU is transferred to the customer and USEC receives payment under normal credit terms without physically delivering the uranium or LEU to the customer. This may occur because the terms of the agreement require USEC to hold the uranium to which the customer has title, or because the customer encounters brief delays in taking delivery of LEU at USEC’s facilities. In such cases, recognition of revenue does not occur at the time title to uranium or LEU transfers to the customer but instead is deferred until LEU to which the customer has title is physically delivered. Related costs associated with deferred revenue, reported in other current assets, totaled $111.4 million at December 31, 2008 and $58.3 million at December 31, 2007.
9. DEBT
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
 	 	(millions)	 	
3.0% convertible senior notes, due October 1, 2014	 	$	575.0	 	 	$	575.0	 	
6.75% senior notes, due January 20, 2009	 	 	95.7	 	 	 	150.0	 	
 	 	 	 	 	 	 	
 	 	$	670.7	 	 	$	725.0	 	
 	 	 	 	 	 	 	
     Convertible Senior Notes due 2014
     In September 2007, USEC issued $575.0 million in convertible notes. The notes bear interest at a rate of 3.0% per annum payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2008. As part of this issuance, USEC paid underwriting discounts and accrued related offering expenses of $14.3 million. These costs are deferred and are being amortized using the effective interest rate method over the life of the convertible notes. Amortization was $0.5 million in 2007 and $1.8 million in 2008.
     The notes are senior unsecured obligations and rank equally with all existing and future senior unsecured debt of USEC Inc. and senior to all subordinated debt of USEC Inc. The notes are structurally subordinated to all existing and future liabilities of subsidiaries of USEC Inc. and will be effectively subordinated to existing and future secured indebtedness of USEC Inc. to the extent of the value of the collateral.
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     Holders may convert their notes to common stock at their option on any day prior to the close of business on the scheduled trading day immediately preceding August 1, 2014 only under the following circumstances: (1) during the five business day period after any five consecutive trading day period in which the price per note for each trading day of that measurement period was less than 98% of the product of the last reported sale price of USEC Inc. common stock and the conversion rate on each such day; (2) during any calendar quarter (and only during such quarter), if the last reported sale price of USEC Inc. common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 120% of the conversion price in effect on the last trading day of the immediately preceding calendar quarter; or (3) upon the occurrence of specified corporate events. The notes will be convertible, regardless of the foregoing circumstances, at any time from, and including, August 1, 2014 through the scheduled trading day immediately preceding the maturity date of the notes. The notes were not eligible for conversion as of December 31, 2008.
     Upon conversion, for each $1,000 in principal amount outstanding, USEC will deliver a number of shares of USEC Inc. common stock equal to the conversion rate. The initial conversion rate for the notes is 83.6400 shares of common stock per $1,000 in principal amount of notes, equivalent to an initial conversion price of approximately $11.956 per share of common stock. The conversion rate will be subject to adjustment in some events but will not be adjusted for accrued interest. In addition, if a make-whole fundamental change (as defined in the indenture governing the notes) occurs prior to the maturity date of the notes, USEC will in some cases increase the conversion rate for a holder that elects to convert its notes in connection with such make-whole fundamental change.
     Subject to certain exceptions, holders may require USEC to repurchase for cash all or part of their notes upon a fundamental change (as defined in the indenture governing the notes) at a price equal to 100% of the principal amount of the notes being repurchased plus any accrued and unpaid interest up to, but excluding, the relevant repurchase date. USEC may not redeem the notes prior to maturity.
     At December 31, 2008, the fair value of the convertible notes, based on quoted market prices, was $207.0 million, compared with the balance sheet carrying amount of $575.0 million.
     Senior Notes due January 20, 2009
     Senior notes bearing interest at 6.75% amounted to $95.7 million in aggregate principal amount at December 31, 2008 and $150.0 million at December 31, 2007. Interest was paid every six months in arrears on January 20 and July 20. The remaining balance of the senior notes was paid on the scheduled maturity date of January 20, 2009. The senior notes were unsecured obligations ranking on parity with all other unsecured and unsubordinated indebtedness of USEC Inc. At December 31, 2008, the fair value of the senior notes calculated based on a credit-adjusted spread over U.S. Treasury securities with similar maturities was $94.9 million.
     Revolving Credit Facility
     In August 2005, USEC entered into a five-year, syndicated bank credit facility, providing up to $400.0 million in revolving credit commitments, including up to $300.0 million in letters of credit, secured by assets of USEC Inc. and its subsidiaries. There were no short-term borrowings under the revolving credit facility at December 31, 2008 or at December 31, 2007. In 2008, aggregate borrowings and repayments amounted to $48.3 million, and the peak amount outstanding was $37.4 million. Letters of credit issued under the facility amounted to $48.0 million at December 31, 2008 and $38.4 million at December 31, 2007.
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     The revolving credit facility is available to finance working capital needs and fund capital programs, including the American Centrifuge project. Financing costs of $3.5 million and $0.3 million to obtain and amend the credit facility, respectively, were deferred and are being amortized over the life of the facility.
     Outstanding borrowings under the credit facility bear interest at a variable rate, which at our election is equal to either:
 	•	 	the sum of (1) the greater of the JPMorgan Chase Bank prime rate and the federal funds rate plus1/2 of 1%, plus (2) a margin ranging from .25% to .75% based upon collateral availability, or	
 	 	 	 	
 	•	 	the sum of LIBOR plus a margin ranging from 2.0% to 2.5% based on collateral availability.	
     Borrowings under the credit facility are subject to limitations based on established percentages of qualifying assets such as eligible accounts receivable and inventory. The credit facility contains various reserve provisions that reduce available borrowings under the facility periodically or restrict the use of borrowings if certain requirements are not met, including those listed below.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	December 31,	 	
 	 	Requirement	 	 	2008	 	 	2007	 	
 	 	(millions)	 	
Available Credit	 	 	 	 	 	$	343.0	 	 	$	361.6	 	
Credit facility provisions:	 	 	 	 	 	 	 	 	 	 	 	 	
Availability	 	 	³ $35.0	 	 	$	342.3	 	 	$	360.9	 	
Collateral Availability	 	 	³ $75.0	 	 	$	342.3	 	 	$	393.3	 	
Available Liquidity	 	 	³ $125.0	 	 	$	591.5	 	 	$	1,247.7	 	
     As of December 31, 2008 and 2007, we met all of the reserve provision requirements by a large margin. However, we expect to have borrowings under the credit facility in 2009, which will reduce Availability, Collateral Availability and Available Liquidity.
     “Available Credit” reflects the levels of qualifying assets at the end of the previous month less any borrowings or letters of credit, and will fluctuate during the year. Qualifying assets are reduced by certain reserves, principally a reserve for future obligations to DOE with respect to the turnover of the gaseous diffusion plants at the end of the term of the lease of these facilities. As a result of the capital USEC raised from the issuance of common stock and convertible notes in September 2007, qualifying assets are no longer reduced by a $150.0 million reserve referred to in the agreement as the “senior note reserve”.
     “Availability” means, the lesser of (i) $400 million and (ii) the sum of eligible receivables and eligible inventory, subject to caps, less the sum of letters of credit issued, outstanding loan balances and accrued interest, fees and expenses. Availability equals Available Credit less accrued interest, fees and expenses.
     “Collateral Availability” means the sum of eligible receivables and eligible inventory, subject to caps, minus the outstanding loans, letters of credit issued and accrued interest, fees and expenses.
     “Available Liquidity” means Availability plus cash balances in accounts controlled by the administrative agent.
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     Additional details regarding these reserve provisions follow.
 	 	 	
Requirement	 	Outcome	
Availability ³ $35 million	 	If not met at any time, an event of default is triggered	
 	 	 	
Collateral Availability ³ $75 million	 	If not met for 7 consecutive days, then fixed charge ratio required to be 1.00 to 1.00 until the 90 th  consecutive day Collateral Availability is restored to $75 million	
 	 	 	
Available Liquidity ³ $125 million	 	If not met for 7 consecutive days, non-financed capital expenditures are limited to $50 million until the 90 th  consecutive day Available Liquidity is restored to $125 million	
     Other reserves under the revolving credit facility, such as availability reserves and borrowing base reserves, are customary for credit facilities of this type.
     The revolving credit facility also includes various customary operating covenants, including restrictions on the incurrence and prepayment of other indebtedness, granting of liens, sales of assets, making of investments, maintenance of a minimum amount of inventory, and payment of dividends or other distributions. Failure to satisfy the covenants would constitute an event of default under the revolving credit facility. In September 2007, the revolving credit facility was amended to specifically permit the issuance of the convertible senior notes described above, and any conversion of the convertible senior notes into common stock.
     A failure by USEC to comply with obligations under the revolving credit facility or other agreements such as the indenture governing USEC’s outstanding convertible notes and the 2002 DOE-USEC Agreement, or the occurrence of a “fundamental change” as defined in the indenture governing USEC’s outstanding convertible notes or the occurrence of a “material adverse effect” as defined in USEC’s credit facility, could result in an event of default under the credit facility. A default, if not cured or waived, could permit acceleration of USEC’s indebtedness.
     DOE Loan Guarantee Program
     Included in other long-term assets are approximately $1.3 million for deferred financing costs related to the DOE Loan Guarantee Program, such as loan guarantee application fees paid to DOE and third-party costs. Deferred financing costs will be amortized over the life of the loan or, if USEC does not receive a loan, charged to expense.
     Other
     In January 2006, USEC repaid the remaining balance of its 6.625% senior notes of $288.8 million on the scheduled maturity date.
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10. PENSION AND POSTRETIREMENT HEALTH AND LIFE BENEFITS
     There are approximately 7,300 employees and retirees covered by defined benefit pension plans providing retirement benefits based on compensation and years of service, and approximately 4,000 employees, retirees and dependents covered by postretirement health and life benefit plans. DOE retained the obligation for postretirement health and life benefits for workers who retired prior to July 28, 1998. Pursuant to the supplemental executive retirement plans (“SERP”) and pension restoration plan, USEC provides executive officers additional retirement benefits in excess of qualified plan limits imposed by tax law. Non-union employees hired on or after September 1, 2008 do not participate in a defined benefit pension plan.
     In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, requiring the recognition in the balance sheet of the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability, and an offsetting adjustment to accumulated other comprehensive income (loss), a component of stockholders’ equity. SFAS No. 158 requires prospective application, and was effective beginning with USEC’s financial statements at December 31, 2006. SFAS No. 158 requires balance sheet recognition of net actuarial losses and prior service costs and benefits (items that are deferred and recognized as net periodic benefit costs in the statement of income over time). SFAS No. 158 also requires that plan assets and benefit obligations be measured at the year-end balance sheet date, which is consistent with USEC’s practice. SFAS No. 158 does not impact the measurement of plan assets and benefit obligations, or the determination of the amount of net periodic benefit cost in the statement of income.
     During 2008 the defined benefit pension plans moved from overfunded to underfunded status driven by a decrease in the value of plan assets. The expected return on plan assets is based on the weighted average of long-term return expectations for the composition of the plans’ equity and debt securities. Expected returns for each asset class are based on historical returns and expectations of future returns. The differences between the actual return on plan assets and expected return on plan assets are accumulated in Net Actuarial Gains and (Losses). The expected return on plan assets for the defined benefit pension plans in 2008 was 8%.
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     Changes in the projected benefit obligations and plan assets and the funded status of the plans follow (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Postretirement Health	 	
 	 	Defined Benefit Pension Plans	 	 	and Life Benefit Plans	 	
 	 	Years Ended December 31,	 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	
 	 	 	 	 	
Changes in Benefit Obligations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations at beginning of year	 	$	737.0	 	 	$	744.4	 	 	$	203.6	 	 	$	202.2	 	
Actuarial (gains) losses, net	 	 	20.3	 	 	 	(31.7	)	 	 	0.6	 	 	 	(5.0	)	
Service costs	 	 	17.4	 	 	 	17.9	 	 	 	4.4	 	 	 	4.1	 	
Interest costs	 	 	45.7	 	 	 	43.1	 	 	 	12.1	 	 	 	11.8	 	
Gross benefits paid	 	 	(37.6	)	 	 	(36.3	)	 	 	(9.7	)	 	 	(9.7	)	
Other	 	 	—	 	 	 	(0.4	)	 	 	—	 	 	 	—	 	
Less federal subsidy on benefits paid	 	 	N/A	 	 	 	N/A	 	 	 	0.2	 	 	 	0.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Obligations at end of year	 	 	782.8	 	 	 	737.0	 	 	 	211.2	 	 	 	203.6	 	

Changes in Plan Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at beginning of year	 	 	780.9	 	 	 	737.7	 	 	 	73.0	 	 	 	73.5	 	
Actual return on plan assets	 	 	(194.8	)	 	 	70.2	 	 	 	(23.8	)	 	 	6.1	 	
USEC contributions	 	 	10.3	 	 	 	9.8	 	 	 	3.6	 	 	 	3.1	 	
Benefits paid	 	 	(37.6	)	 	 	(36.3	)	 	 	(9.7	)	 	 	(9.7	)	
Other	 	 	—	 	 	 	(0.5	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at end of year	 	 	558.8	 	 	 	780.9	 	 	 	43.1	 	 	 	73.0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded (Unfunded) status at end of year	 	 	(224.0	)	 	 	43.9	 	 	 	(168.1	)	 	 	(130.6	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Amounts recognized in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Noncurrent assets	 	$	—	 	 	$	67.1	 	 	$	—	 	 	$	—	 	
Current liabilities	 	 	(0.9	)	 	 	(0.2	)	 	 	—	 	 	 	—	 	
Noncurrent liabilities	 	 	(223.1	)	 	 	(23.0	)	 	 	(168.1	)	 	 	(130.6	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	(224.0	)	 	$	43.9	 	 	$	(168.1	)	 	$	(130.6	)	

Amounts recognized in accumulated other comprehensive income, pre-tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net actuarial loss (gain)	 	$	302.0	 	 	$	26.0	 	 	$	55.1	 	 	$	26.2	 	
Prior service cost (credit)	 	 	7.5	 	 	 	9.2	 	 	 	(23.0	)	 	 	(37.4	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	309.5	 	 	$	35.2	 	 	$	32.1	 	 	$	(11.2	)	

Assumptions used to determine benefit obligations at end of year:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	6.09	%	 	 	6.21	%	 	 	6.00	%	 	 	5.96	%	
Compensation increases	 	 	4.25	 	 	 	4.25	 	 	 	4.25	 	 	 	4.25	 	
     Projected benefit obligations for the defined benefit pension plans and the postretirement health and life benefit plans were discounted at weighted average rates of 6.09% and 6.00%, respectively, to determine the present values of the obligations as of December 31, 2008. The discount rates are the estimated rates at which the benefit obligations could be effectively settled on the measurement date and are based on yields of high quality fixed income investments whose cash flows match the timing and amount of expected benefit payments of the plans.
     The current portion of underfunded plan liabilities represents the expected benefit payments for the following year in excess of the fair value of the plan assets at year-end. Therefore, the current liability reflects projected benefit payments for SERP and the pension restoration plan in the following year.
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     Projected benefit obligations are based on actuarial assumptions including future increases in compensation. Accumulated benefit obligations are based on actuarial assumptions but do not include possible future increases in compensation. The accumulated benefit obligation for all defined benefit pension plans was $704.5 million at December 31, 2008 and $661.9 million at December 31, 2007. At December 31, 2008, none of USEC’s plans had fair value of plan assets in excess of accumulated benefit obligations.
     The expected cost of providing pension benefits is accrued over the years employees render service, and actuarial gains and losses are amortized over the employees’ average future service life. For postretirement health and life benefits, actuarial gains and losses and prior service costs or benefits are amortized over the employees’ average remaining years of service from age 40 until the date of full benefit eligibility.
     USEC began receiving federal subsidy payments in 2006 in connection with a change in Medicare law affecting corporations that sponsor prescription drug benefits. The Medicare Prescription Drug Improvement and Modernization Act of 2003 provides prescription drug benefits under Medicare (“Medicare Part D”) as well as federal subsidy payments to sponsors of plans that provide prescription drug benefits that are at least actuarially equivalent to Medicare Part D. USEC, in consultation with its actuaries, has determined that the prescription drug provisions of its postretirement health benefit plan are at least actuarially equivalent to Medicare Part D.
     The components of net benefit costs for pension and postretirement health and life benefit plans were as follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Postretirement Health	 	
 	 	Defined Benefit Pension Plans	 	 	and Life Benefit Plans	 	
 	 	Years Ended December 31,	 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	 	2008	 	 	2007	 	 	2006	 	
Service costs	 	$	17.4	 	 	$	17.9	 	 	$	18.3	 	 	$	4.4	 	 	$	4.1	 	 	$	4.7	 	
Interest costs	 	 	45.7	 	 	 	43.1	 	 	 	40.7	 	 	 	12.1	 	 	 	11.8	 	 	 	11.0	 	
Expected return on plan assets (gains)	 	 	(61.4	)	 	 	(58.0	)	 	 	(53.8	)	 	 	(5.2	)	 	 	(5.6	)	 	 	(5.5	)	
Amortization of prior service costs (credit)	 	 	1.7	 	 	 	1.8	 	 	 	1.7	 	 	 	(14.5	)	 	 	(14.5	)	 	 	(14.5	)	
Amortization of actuarial (gains) losses, net	 	 	0.7	 	 	 	1.3	 	 	 	5.3	 	 	 	0.7	 	 	 	2.2	 	 	 	2.6	 	
Other special charges	 	 	—	 	 	 	0.1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net benefit costs	 	$	4.1	 	 	$	6.2	 	 	$	12.2	 	 	$	(2.5	)	 	$	(2.0	)	 	$	(1.7	)	

Assumptions used to determine net benefit costs:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	6.21	%	 	 	5.75	%	 	 	5.50	%	 	 	5.96	%	 	 	5.75	%	 	 	5.50	%	
Expected return on plan assets	 	 	8.00	 	 	 	8.00	 	 	 	8.00	 	 	 	7.50	 	 	 	8.00	 	 	 	8.00	 	
Compensation increases	 	 	4.25	 	 	 	4.00	 	 	 	3.75	 	 	 	4.25	 	 	 	4.00	 	 	 	3.75	 	
     The estimated actuarial net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic pension benefit cost during 2009 are $23.9 million and $1.7 million, respectively. The estimated actuarial net loss and prior service cost credit for the postretirement health and life plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost during 2009 are $4.2 million and $(14.5) million, respectively.
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     Healthcare cost trend rates used to measure postretirement health benefit obligations follow:
 	 	 	 	 	 	 	 	 	
 	 	December 31,	
 	 	2008	 	2007	
Healthcare cost trend rate for the following year	 	 	8.25	%	 	 	9.00	%	
Long-term rate that the healthcare cost trend rate gradually declines to	 	 	5	%	 	 	5	%	
Year that the healthcare cost trend rate is expected to reach the long-term rate	 	 	2016	 	 	 	2014	 	
     A one-percentage-point change in the assumed healthcare cost trend rates would have an effect on the postretirement health benefit obligation and costs, as follows (in millions):
 	 	 	 	 	 	 	 	 	
 	 	One Percentage Point	
 	 	Increase	 	Decrease	
Postretirement health benefit obligation	 	$	8.6	 	 	$	(8.3	)	
Net benefit costs	 	$	1.0	 	 	$	(0.9	)	
Benefit Plan Assets
     Independent investment advisors manage assets in each category to maximize investment returns within reasonable and prudent levels of risk. Risk is reduced by diversifying plan assets in a broad mix of asset classes and by following a strategic asset allocation approach. Asset classes and target weights are adjusted periodically to optimize the long-term portfolio risk/return tradeoff, to provide liquidity for benefit payments, and to align portfolio risk with the underlying obligations. In 2008, actual returns for the defined benefit pension plan assets were significantly below the expected long-term rate of return on plan assets of 8% due to adverse conditions in the financial markets.
     The allocation of plan assets between equity and debt securities and the target allocation range by asset category follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Percentage of	 	Target	
 	 	Plan Assets	 	Allocation	
 	 	December 31,	 	Range	
 	 	2008	 	2007	 	2008	
Defined Benefit Pension Plans:	 	 	 	 	 	 	 	 	 	 	 	 	
Equity securities	 	 	50	%	 	 	60	%	 	 	40-60	%	
Debt securities	 	 	50	 	 	 	40	 	 	 	40-60	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	100	%	 	 	100	%	 	 	 	 	

Postretirement Health and Life Benefit Plans:	 	 	 	 	 	 	 	 	 	 	 	 	
Equity securities	 	 	67	%	 	 	65	%	 	 	55-75	%	
Debt securities	 	 	33	 	 	 	35	 	 	 	25-45	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	100	%	 	 	100	%	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     In order to attempt to reduce the volatility of pension plan assets and also to better align plan assets with liabilities, the target equity allocation was reduced in 2008 by 10% and the target fixed income allocation was increased by 10%.
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Benefit Plan Cash Flows
     USEC expects cash contributions to the plans in 2009 will be as follows: $23.6 million for the defined benefit pension plans and $5.3 million for the postretirement health and life benefit plans.
     Estimated future benefit plan payments and expected subsidies from Medicare follow (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Postretirement	 	Expected	
 	 	Defined Benefit	 	Health and Life	 	Subsidies	
 	 	Pension Plans	 	Benefit Plans	 	From Medicare	
2009	 	$	39.2	 	 	$	11.4	 	 	$	0.3	 	
2010	 	 	41.0	 	 	 	13.2	 	 	 	0.4	 	
2011	 	 	42.6	 	 	 	14.9	 	 	 	0.5	 	
2012	 	 	51.2	 	 	 	16.3	 	 	 	0.7	 	
2013	 	 	46.9	 	 	 	17.8	 	 	 	0.9	 	
2014 to 2018	 	 	273.1	 	 	 	108.7	 	 	 	7.4	 	
Other Plans
     USEC sponsors a 401(k) defined contribution plan for employees. Employee contributions are matched at established rates. Amounts contributed are invested in a range of investment options available to participants, and the funds are administered by an independent trustee. USEC’s matching cash contributions amounted to $7.4 million in 2008, $6.6 million in 2007 and $6.1 million in 2006. Under the Executive Deferred Compensation Plan (and previously under the 401(k) Restoration Plan), qualified employees contribute and USEC matches contributions in excess of amounts eligible under the 401(k) plan. USEC’s matching contributions amounted to $0.1 million in each of 2008, 2007 and 2006.
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11. STOCK-BASED COMPENSATION
     USEC has stock-based compensation plans available to grant restricted stock, restricted stock units, non-qualified stock options, performance awards and other stock-based awards to key employees and non-employee directors, as well as an employee stock purchase plan. A summary of stock-based compensation costs follows (in millions).
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
Total stock-based compensation costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock and restricted stock units	 	$	5.1	 	 	$	5.2	 	 	$	3.5	 	
Stock options, performance awards and other	 	 	1.2	 	 	 	0.8	 	 	 	0.8	 	
Less: costs capitalized as part of inventory	 	 	(0.2	)	 	 	(0.3	)	 	 	(0.3	)	
 	 	 	 	 	 	 	 	 	 	
Expense included in selling, general and administrative	 	$	6.1	 	 	$	5.7	 	 	$	4.0	 	
 	 	 	 	 	 	 	 	 	 	
Total after-tax expense	 	$	3.9	 	 	$	3.6	 	 	$	2.6	 	
 	 	 	 	 	 	 	 	 	 	
     As of December 31, 2008, there was $4.1 million of unrecognized compensation cost, adjusted for estimated forfeitures, related to non-vested stock-based payments granted, of which $2.7 million relates to restricted shares and restricted stock units, and $1.4 million relates to stock options. That cost is expected to be recognized over a weighted-average period of 1.6 years.
     Of the 16.9 million shares of common stock approved by stockholders for issuance under USEC’s equity incentive plan and employee stock purchase plan, there were 5,404,000 shares available for future awards under the plan at December 31, 2008 (excluding outstanding awards which terminate or are cancelled without being exercised or that are settled for cash), including 4,036,000 shares available for grants of stock options and 1,368,000 shares available for restricted stock or restricted stock units, performance awards and other stock-based awards, as well as the employee stock purchase plan. USEC’s practice is to issue shares under stock-based compensation plans from treasury stock.
Restricted Stock Units and Restricted Stock
     Under the long-term incentive program established in April 2006, the target award denominated in shares of USEC stock is determined based on the average closing price of USEC’s common stock in the calendar month prior to the beginning of the performance period. The awards are then marked to market each period, with 80% of the adjustment based on the ending price of USEC’s common stock. The remaining 20% is based on a market condition and is valued using a Monte Carlo model. Compensation cost for these awards is generally recognized over a three-year service period. The awards can be settled in cash or USEC stock, or can be deferred for future settlement at the employee’s discretion. Since there is the potential for cash settlement, the awards are classified as a liability. Non-employee directors are granted restricted stock units as part of their compensation for serving on the Board of Directors which can only be settled in USEC stock. The restricted stock units vest over one or three years.
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     The fair value of restricted stock is determined based on the closing price of USEC’s common stock on the grant date. Compensation cost for restricted stock is amortized to expense on a straight-line basis over the vesting period, which, depending on the grant, is amortized ratably over a one-, three- or five-year period. Sale of such shares is restricted prior to the date of vesting. A summary of restricted shares activity for the year ended December 31, 2008 follows (shares in thousands):
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted-Average	
 	 	 	 	 	 	Grant-Date	
 	 	Shares	 	Fair Value	
Restricted Shares at December 31, 2007	 	 	788	 	 	$	10.82	 	
Granted	 	 	820	 	 	 	5.84	 	
Vested	 	 	(338	)	 	 	11.15	 	
Forfeited	 	 	(13	)	 	 	13.09	 	
 	 	 	 	 	 	 	 	 	
Restricted Shares at December 31, 2008	 	 	1,257	 	 	$	7.46	 	
 	 	 	 	 	 	 	 	 	
Stock Options
     The intrinsic value of an option, if any, represents the excess of the fair value of the common stock over the exercise price. The determination of the fair value of stock option awards is affected by USEC’s stock price and a number of complex and subjective variables. Fair value is estimated using the Black-Scholes option pricing model, which includes a number of assumptions including USEC’s estimates of stock price volatility, employee stock option exercise behaviors, future dividend payments, and risk-free interest rates.
     The expected term of options granted is the estimated period of time from the beginning of the vesting period to the date of expected exercise or other settlement, based on historical exercises and post-vesting terminations. Future stock price volatility is estimated based on historical volatility for the recent period equal to the expected term of the options. The risk-free interest rate for the expected option term is based on the U.S. Treasury yield curve in effect at the time of grant. No cash dividends are expected in the foreseeable future and therefore an expected dividend yield of zero is used in the option valuation model. Historical data are used to estimate pre-vesting option forfeitures at the time of grant. Estimates for option forfeitures are revised in subsequent periods if actual forfeitures differ from those estimates. Compensation expense is recognized for stock option awards that are expected to vest.
     Assumptions used to value option grants follow:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	
 	 	2008	 	2007	 	2006	
Risk-free interest rate	 	 	1.84-2.62	%	 	 	4.5	%	 	 	4.6	%	
Expected dividend yield	 	 	—	 	 	 	—	 	 	 	—	 	
Expected volatility	 	 	50-56	%	 	 	42	%	 	 	41	%	
Expected option life	 	3.5 years	 	3.5 years	 	3.5 years	
Weighted-average grant date fair value	 	$	2.23	 	 	$	4.77	 	 	$	4.21	 	
Options granted	 	 	818,000	 	 	 	258,000	 	 	 	288,000	 	
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     Stock options vest or become exercisable in equal annual installments over a one to three year period and expire 5 or 10 years from the date of grant. A summary of stock option activity follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Weighted-Average	 	 	
 	 	Stock	 	Weighted-	 	Remaining	 	Aggregate	
 	 	Options	 	Average	 	Contractual	 	Intrinsic Value	
 	 	(thousands)	 	Exercise Price	 	Term (years)	 	(millions)	
Outstanding at December 31, 2007	 	 	1,318	 	 	 	10.23	 	 	 	 	 	 	 	 	 	
Granted	 	 	818	 	 	 	5.85	 	 	 	 	 	 	 	 	 	
Exercised	 	 	—	 	 	 	—	 	 	 	 	 	 	 	 	 	
Forfeited or expired	 	 	(16	)	 	 	12.65	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2008	 	 	2,120	 	 	$	8.52	 	 	 	1.5	 	 	$	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at December 31, 2008	 	 	1,077	 	 	$	9.64	 	 	 	2.3	 	 	$	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     Cash received from the exercise of stock options was $0.8 million in 2007 and $2.1 million in 2006. The total intrinsic value of options exercised was $1.0 million in 2007 and $1.3 million in 2006. There were no options exercised in 2008.
     Stock options outstanding and options exercisable at December 31, 2008, follow (options in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted	 	 	
 	 	 	 	 	 	Average	 	 	
 	 	 	 	 	 	Remaining	 	 	
Stock Exercise	 	Options	 	Contractual	 	Options	
Price	 	Outstanding	 	Life in Years	 	Exercisable	
$3.63 to $7.00	 	 	1,033	 	 	 	0.6	 	 	 	216	 	
7.02 to 7.13	 	 	151	 	 	 	3.1	 	 	 	151	 	
8.05	 	 	104	 	 	 	0.2	 	 	 	104	 	
8.50	 	 	142	 	 	 	2.6	 	 	 	142	 	
10.44 to 11.88	 	 	103	 	 	 	1.7	 	 	 	103	 	
12.09	 	 	225	 	 	 	2.3	 	 	 	149	 	
12.19 to 14.28	 	 	275	 	 	 	3.0	 	 	 	125	 	
16.90	 	 	87	 	 	 	1.3	 	 	 	87	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2,120	 	 	 	1.5	 	 	 	1,077	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Employee Stock Purchase Plan
     Under the employee stock purchase plan, participating employees may purchase shares of USEC Inc. common stock at 85% of the market price at the end of the six-month offer period. There is a minimum holding period of one year. Employees can elect to designate up to 10% of their compensation to purchase common stock under the plan. USEC is required to recognize the compensation costs for the discounts provided under the plan effective January 1, 2006. USEC recognized expense of $0.1 million in each of the years ended December 31, 2008 and 2007 related to this plan. Shares purchased by employees amounted to approximately 132,000 in 2008 and approximately 54,000 in 2007. At December 31, 2008, there were 211,000 remaining shares available for purchase under the plan.
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12. INCOME TAXES
Provision
     The provision for income taxes from continuing operations is as follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
Current:	 	 	 	 	 	 	 	 	 	 	 	 	
Federal	 	$	13.7	 	 	$	68.3	 	 	$	70.4	 	
State and local	 	 	6.2	 	 	 	7.5	 	 	 	7.2	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	19.9	 	 	 	75.8	 	 	 	77.6	 	

Deferred:	 	 	 	 	 	 	 	 	 	 	 	 	
Federal	 	 	2.5	 	 	 	(41.2	)	 	 	(14.4	)	
State and local	 	 	0.6	 	 	 	0.6	 	 	 	1.0	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	3.1	 	 	 	(40.6	)	 	 	(13.4	)	
 	 	 	 	 	 	 	 	 	 	
 	 	$	23.0	 	 	$	35.2	 	 	$	64.2	 	
 	 	 	 	 	 	 	 	 	 	
Deferred Taxes
     Future tax consequences of temporary differences between the carrying amounts for financial reporting purposes and USEC’s estimate of the tax bases of its assets and liabilities result in deferred tax assets and liabilities, as follows (in millions):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	
Deferred tax assets:	 	 	 	 	 	 	 	 	
Plant lease turnover and other exit costs	 	$	23.2	 	 	$	23.9	 	
Employee benefits costs	 	 	166.5	 	 	 	57.4	 	
Inventory	 	 	44.8	 	 	 	28.7	 	
Property, plant and equipment	 	 	47.1	 	 	 	66.9	 	
Tax intangibles	 	 	3.4	 	 	 	4.4	 	
Deferred costs for depleted uranium	 	 	46.1	 	 	 	38.7	 	
Net operating loss carryforwards	 	 	1.6	 	 	 	1.9	 	
Accrued expenses	 	 	6.1	 	 	 	7.3	 	
Other	 	 	5.2	 	 	 	3.4	 	
 	 	 	 	 	 	 	
 	 	$	344.0	 	 	$	232.6	 	
Valuation allowance	 	 	(1.5	)	 	 	(1.8	)	
 	 	 	 	 	 	 	
Deferred tax assets, net of valuation allowance	 	 	342.5	 	 	 	230.8	 	
 	 	 	 	 	 	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	 	
Prepaid expenses	 	 	1.3	 	 	 	1.2	 	
 	 	 	 	 	 	 	
Deferred tax liabilities	 	 	1.3	 	 	 	1.2	 	
 	 	 	 	 	 	 	
 	 	$	341.2	 	 	$	229.6	 	
 	 	 	 	 	 	 	
     The valuation allowances of $1.5 million and $1.8 million at December 31, 2008 and 2007, respectively, reduce deferred tax assets and are recorded as a result of the acquisition of NAC, and relate to state net operating losses that are available to offset future taxable income of NAC. The NAC state net operating losses currently expire through 2023. A valuation allowance is provided if it is more likely than not that all or a portion of a deferred tax asset will not be realized. Tax benefits earned or expected to be earned from the net operating losses are recorded as reductions to goodwill and have been reflected in the balance. The goodwill amount will not be deductible for income tax purposes. The $0.3 million decrease to the valuation allowance and net operating loss carryforwards recorded in 2008 did not affect the deferred tax provision and was attributable to state net operating losses that expired as of December 31, 2008 for which full valuation allowances were previously recorded. The deferred tax asset, net of valuation allowance, is more likely than not to be realized in future years based on an assessment of positive and negative available evidence.
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Effective Tax Rate
     A reconciliation of income taxes calculated based on the federal statutory income tax rate of 35% and the effective tax rate follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	
 	 	2008	 	2007	 	2006	
Federal statutory tax rate	 	 	35	%	 	 	35	%	 	 	35	%	
State income taxes, net of federal	 	 	5	 	 	 	3	 	 	 	2	 	
Export tax incentives	 	 	—	 	 	 	(1	)	 	 	(1	)	
Research and other tax credits	 	 	(6	)	 	 	(1	)	 	 	(1	)	
Manufacturing deduction	 	 	—	 	 	 	(1	)	 	 	—	 	
Other nondeductible expenses	 	 	1	 	 	 	—	 	 	 	1	 	
Impact of state rate changes on deferred taxes	 	 	1	 	 	 	1	 	 	 	2	 	
FIN 48 uncertain tax positions (see below)	 	 	(4	)	 	 	(9	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	32	%	 	 	27	%	 	 	38	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	
FIN 48 Uncertain Tax Positions
     In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). This interpretation clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before the related tax benefit may be recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.
     USEC adopted the provisions of FIN 48 effective January 1, 2007. As a result of implementing FIN 48, USEC recognized a $31.1 million increase in the liability for unrecognized tax benefits. This increase resulted in a $7.5 million decrease in the January 1, 2007 retained earnings balance and a $23.6 million increase in the deferred tax assets. Implementation of FIN 48 also resulted in an additional $11.4 million decrease in the January 1, 2007 retained earnings balance for accrued interest and penalties. The liability for unrecognized tax benefits was $38.5 million at January 1, 2007, of which $19.5 million would impact the effective tax rate, if recognized.
     A reconciliation of the beginning and ending amount of unrecognized benefits is as follows (in millions):
 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	
Balance at beginning of the year	 	$	10.8	 	 	$	38.5	 	
Additions to tax positions of prior years	 	 	—	 	 	 	5.6	 	
Reductions to tax positions of prior years.	 	 	(7.3	)	 	 	(4.2	)	
Additions for tax positions of current year	 	 	0.3	 	 	 	1.1	 	
Settlements	 	 	—	 	 	 	(12.2	)	
Statute expiration	 	 	—	 	 	 	(18.0	)	
 	 	 	 	 	 	 	
Balance at end of the year (1)	 	$	3.8	 	 	$	10.8	 	
 	 	 	 	 	 	 	
Liability decrease	 	$	7.0	 	 	$	27.7	 	

 	 	 	
(1)	 	Amount for unrecognized tax benefits included in other long-term liabilities.	
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     During 2008, the liability for unrecognized tax benefits decreased $7.0 million, of which $2.9 million decreased the tax provision. The decrease was primarily as a result of the completion of the 2004 through 2006 IRS examination and the filing of a tax accounting method change.
     During 2007, the liability for unrecognized tax benefits decreased $27.7 million, of which $12.6 million decreased the tax provision. The decrease was primarily a result of the expiration of the federal statute of limitations for all tax years through 2003, the resolution of an issue with the IRS, and the completion of the IRS examination.
     The $2.9 million and $12.6 million tax provision decrease reduced the effective tax rate by 4% and 9% for 2008 and 2007, respectively, as shown in the rate reconciliation above. All of the liability balance at December 31, 2008 of $3.8 million would affect the effective tax rate, if recognized. USEC believes that the liability for unrecognized tax benefits will not materially change in the next 12 months.
     USEC and its subsidiaries file income tax returns with the U.S. government and various states and foreign jurisdictions. In the third quarter of 2007, the IRS completed USEC’s federal income tax return examination for tax years 1998 through 2003. As of December 31, 2008, the federal statute of limitations is closed with respect to all tax years through 2003. The IRS commenced an examination of USEC’s 2004 through 2006 federal income tax returns during 2007, and the exam was completed in July 2008. As of December 31, 2008, the applicable Kentucky and Ohio statutes of limitations for tax years 2004 forward and 2005 forward, respectively, had not yet expired.
     USEC recognizes accrued interest as a component of interest expense and accrued penalties as a component of selling, general and administrative expense in the consolidated statement of income, which is consistent with the reporting for these items in periods prior to the implementation of FIN 48. After implementation of FIN 48, USEC’s balance of accrued interest and penalties was $19.5 million at January 1, 2007. Expenses for accrued interest and penalties totaled $0.5 million during 2008 and $3.3 million during 2007. During 2008, $1.5 million of previously accrued interest and penalties were reversed primarily as a result of the completion of the IRS exams for 2004 through 2006 and the filing of a tax accounting method change. During 2007, $16.4 million of previously accrued interest and penalties were reversed as a result of the expiration of the federal statute of limitations and the completion of the IRS examination for all tax years through 2003. The reversal of previously accrued interest was recorded as interest income and the reversal of the previously accrued penalties was recorded as a reduction to selling, general and administrative expense in the consolidated statement of income. As a result of settling the IRS examinations through 2003, USEC made an interest payment to the IRS of $3.5 million in September 2007 and interest payments totaling $1.0 million to various states in December 2007. Accrued interest and penalties as of December 31, 2008 totaled $0.9 million and as of December 31, 2007 totaled $1.9 million.
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13. STOCKHOLDERS’ EQUITY
Common Stock
     Changes in the number of shares of common stock outstanding follow (in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Shares	 	Treasury	 	Shares	
 	 	Issued	 	Stock	 	Outstanding	
Balance at December 31, 2005	 	 	100,320	 	 	 	(13,749	)	 	 	86,571	 	
Common stock issued	 	 	—	 	 	 	571	 	 	 	571	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2006	 	 	100,320	 	 	 	(13,178	)	 	 	87,142	 	
Common stock issued	 	 	23,000	 	 	 	437	 	 	 	23,437	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2007	 	 	123,320	 	 	 	(12,741	)	 	 	110,579	 	
Common stock issued	 	 	—	 	 	 	1,177	 	 	 	1,177	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2008	 	 	123,320	 	 	 	(11,564	)	 	 	111,756	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     In September 2007, USEC issued 23 million shares of common stock raising net proceeds of approximately $214 million after underwriter commissions and offering expenses.
Preferred Stock Purchase Rights
     In April 2001, the Board of Directors approved a shareholder rights plan, under which shareholders of record on May 9, 2001 received rights that initially trade together with USEC common stock and are not exercisable. In the absence of further action by the Board, the rights generally would become exercisable and allow the holder to acquire USEC common stock at a discounted price if a person or group acquires 15% or more of the outstanding shares of USEC common stock or commences a tender or exchange offer to acquire 15% or more of the common stock of USEC. However, any rights held by the acquirer would not be exercisable. The Board of Directors may direct USEC to redeem the rights at $.01 per right at any time before the tenth day following the acquisition of 15% or more of USEC common stock by a person or group.
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14. NET INCOME PER SHARE
     Basic net income per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period, excluding any unvested restricted stock.
     In calculating diluted net income per share, the numerator is increased by interest expense on the convertible notes, net of tax, and the denominator is increased by the weighted average number of shares resulting from potentially dilutive stock compensation awards and the convertible notes, assuming full conversion. Conversion of the convertible notes is not assumed if the effect is antidilutive. Convertible debt is antidilutive if foregone interest on the notes (net of tax and nondiscretionary adjustments) per common share obtainable upon full conversion exceeds basic net income per share.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Numerator:	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	48.7	 	 	$	96.6	 	 	$	106.2	 	
Interest expense on convertible notes — net of tax	 	 	6.5	 	 	 	2.9	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net income if-converted	 	$	55.2	 	 	$	99.5	 	 	$	106.2	 	

Denominator:	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average common shares	 	 	111.4	 	 	 	93.4	 	 	 	86.9	 	
Less: Weighted average unvested restricted stock	 	 	0.8	 	 	 	0.4	 	 	 	0.3	 	
 	 	 	 	 	 	 	 	 	 	
Denominator for basic calculation	 	 	110.6	 	 	 	93.0	 	 	 	86.6	 	

Weighted average effect of dilutive securities:	 	 	 	 	 	 	 	 	 	 	 	 	
Convertible notes	 	 	48.1	 	 	 	12.5	 	 	 	—	 	
Stock compensation awards	 	 	—	 	 	 	0.3	 	 	 	0.2	 	
 	 	 	 	 	 	 	 	 	 	
Denominator for diluted calculation	 	 	158.7	 	 	 	105.8	 	 	 	86.8	 	

Net income per share — basic	 	$	.44	 	 	$	1.04	 	 	$	1.22	 	
 	 	 	 	 	 	 	 	 	 	
Net income per share — diluted	 	$	.35	 	 	$	.94	 	 	$	1.22	 	
 	 	 	 	 	 	 	 	 	 	
     Options to purchase shares of common stock having an exercise price greater than the average share market price are excluded from the calculation of diluted earnings per share (options in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	
 	 	2008	 	2007	 	2006	
Options excluded from diluted earnings per share	 	 	2.0	 	 	 	0.1	 	 	 	0.4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercise price of excluded options	 	$	5.86 to $16.90	 	 	$	16.90	 	 	$	11.88 to $16.90	 	
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15. ENVIRONMENTAL COMPLIANCE
     Environmental compliance costs include the handling, treatment and disposal of hazardous substances and wastes. Pursuant to the USEC Privatization Act, environmental liabilities associated with the Paducah and Portsmouth GDPs prior to July 28, 1998 are the responsibility of the U.S. government, except for liabilities relating to certain identified wastes generated by USEC and stored at the GDPs.
Depleted Uranium
     USEC stores depleted uranium at the Paducah and Portsmouth GDPs and accrues estimated costs for its future disposition. USEC anticipates that it will send most or all of its depleted uranium to DOE for disposition unless a more economic disposal option becomes available. DOE is constructing facilities at the Paducah and Portsmouth GDPs to process large quantities of depleted uranium owned by DOE. Under federal law, DOE would also process USEC’s depleted uranium if provided to DOE. If we were to dispose of our uranium this way, USEC would be required to reimburse DOE for the related disposition costs of our depleted uranium, including a pro rata share of DOE’s capital costs. Processing DOE’s depleted uranium is expected to take about 25 years. The timing of the disposal of USEC’s depleted uranium has not been determined. The long-term liability for depleted uranium disposition is dependent upon the volume of depleted uranium generated and estimated processing, transportation and disposal costs. USEC’s estimate of the unit disposal cost is based primarily on estimated cost data obtained from DOE without consideration given to contingencies or reserves. USEC’s estimate is periodically reviewed as additional information becomes available. USEC’s estimate of the unit disposition cost for accrual purposes is approximately 35% less than the unit disposition cost for financial assurance purposes, which includes contingencies and other potential costs as required by the NRC.
     Compliance with NRC regulations requires that USEC provide financial assurance regarding the cost of the eventual disposition of USEC’s depleted uranium and stored wastes. The financial assurance requirement is based on our year-end liability plus expected volume increases over the coming year, including NRC required contingencies, totaling to an annual projected required amount. At December 31, 2008, the financial assurance requirements in place for 2009, principally the amount associated with disposition of depleted uranium, total $232.0 million and are covered by a combination of $204.5 million under surety bonds and a $27.5 million letter of credit.
     USEC’s estimated cost and accrued liability for depleted uranium disposition, as well as related financial assurance USEC provides, are subject to change as additional information becomes available.
Stored Wastes
     USEC’s operations generate hazardous, low-level radioactive and mixed wastes. The storage, treatment, and disposal of wastes are regulated by federal and state laws. USEC utilizes offsite treatment and disposal facilities and stores wastes at the Paducah and Portsmouth GDPs pursuant to permits, orders and agreements with DOE and various state agencies. Liabilities accrued for the treatment and disposal of stored wastes generated by USEC’s operations amounted to $6.0 million at December 31, 2008 and $4.7 million at December 31, 2007.
GDP Lease Turnover
     At the conclusion of the GDP lease with DOE, USEC may leave the property in an “as is” condition, but must remove all wastes generated by USEC, which are subject to off-site disposal, and must place the GDPs in a safe shutdown condition. Accrued liabilities for lease turnover costs amounted to $55.4 million at December 31, 2008 and $56.9 million at December 31, 2007.
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American Centrifuge Decontamination and Decommissioning
     Financial Assurance
     USEC leases facilities in Piketon, Ohio from DOE for the American Centrifuge Plant. At the conclusion of the 36-year lease period in 2043, assuming no further extensions, USEC is obligated to return these leased facilities to DOE in a condition that meets NRC requirements and in the same condition as the facilities were in when they were leased to USEC (other than due to normal wear and tear). USEC owns all capital improvements at the American Centrifuge Plant and, unless otherwise consented to by DOE, must remove them by the conclusion of the lease term. USEC is required to provide financial assurance to the NRC incrementally based on facility construction and centrifuge installation. USEC is also required to provide financial assurance to DOE in an amount equal to its current estimate of costs to comply with lease turnover requirements, less the amount of financial assurance required of USEC by the NRC for decontamination and decommissioning (“D&D”). As of December 31, 2008, USEC has provided financial assurance to the NRC and DOE for 2009 in the form of surety bonds totaling $57.7 million.
     The financial assurance requirements will increase each year commensurate with the status of facility construction and operations. As part of USEC’s license to operate the American Centrifuge Plant, USEC provides the NRC with a projection of the total D&D cost. The current estimate of the total cost related to NRC requirements is $377.3 million in 2008 dollars, and the projected total incremental lease turnover cost related to DOE is estimated to be $25.5 million in 2008 dollars. Financial assurance will also be required for the disposition of depleted uranium generated from future centrifuge operations.
     Asset Retirement Obligations
     Commensurate with the American Centrifuge Plant commercial lease signed in December 2006, USEC recorded the financial assurance amount for 2006 of $8.8 million as the estimate of the present value of the asset retirement obligation at year end. In 2007, USEC reassessed and revised the estimate of the asset retirement obligation reducing the amount recorded in both construction work in progress and other long-term liabilities. The estimate is also revised for any changes in long-term inflation rate assumptions. Additional retirement obligations are recognized as construction progress continues as indicated by the increase during 2008. Changes in USEC’s asset retirement obligation liability balance since December 31, 2006 follow (in millions):
 	 	 	 	 	
Balance at December 31, 2006	 	$	8.8	 	
Additional retirement obligation and revision of estimate	 	 	(4.6	)	
Time value accretion	 	 	0.2	 	
 	 	 	 	
Balance at December 31, 2007	 	$	4.4	 	
Additional retirement obligation	 	 	8.8	 	
Time value accretion	 	 	0.5	 	
 	 	 	 	
Balance at December 31, 2008	 	$	13.7	 	
 	 	 	 	
Surety Bond Collateral
     Other long-term assets at December 31, 2008 include interest-earning cash deposits of $135.1 million provided as collateral for surety bonds relating primarily to depleted uranium and American Centrifuge Plant decontamination and decommissioning.
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16. COMMITMENTS AND CONTINGENCIES
Power Contracts and Commitments
     The gaseous diffusion process uses significant amounts of electric power to enrich uranium. USEC purchases most of the electric power for the Paducah GDP from the Tennessee Valley Authority (“TVA”) under an agreement for power deliveries through May 2012. Capacity under the agreement is fixed. As of December 31, 2008, USEC is obligated to make minimum payments under the agreement, whether or not it takes delivery of electric power, of approximately $1.7 billion through May 2012. USEC’s costs are subject to monthly fuel cost adjustments to reflect changes in TVA’s fuel costs, purchased power costs, and related costs.
American Centrifuge Plant
     Milestones under the 2002 DOE-USEC Agreement
     USEC is working to construct and deploy the American Centrifuge Plant as a replacement for the Paducah GDP. In 2002, USEC and DOE signed an agreement (such agreement, as amended, the “2002 DOE-USEC Agreement”) in which USEC and DOE made long-term commitments directed at resolving issues related to the stability and security of the domestic uranium enrichment industry. The 2002 DOE-USEC Agreement contains specific project milestones relating to the American Centrifuge Plant. At USEC’s request, the last four milestones were amended in January 2009 to replace milestones that were not aligned with USEC’s deployment schedule for the American Centrifuge Plant. The first of the new milestones requires that USEC secure firm financing commitment(s) by November 2009 for the construction of the commercial American Centrifuge Plant with an annual capacity of approximately 3.5 million SWU per year.
     Until USEC has met the November 2009 financing milestone, DOE has full remedies under the 2002 DOE-USEC Agreement. However, if a delaying event beyond the control and without the fault or negligence of USEC occurs which would affect USEC’s ability to meet a milestone, DOE and USEC will jointly meet to discuss in good faith possible adjustments to the milestones as appropriate to accommodate the delaying event. Once USEC has met the November 2009 financing milestone, DOE’s remedies under the 2002 DOE-USEC Agreement are limited to those circumstances where USEC’s gross negligence in project planning and execution is responsible for schedule delays or in the circumstance where USEC constructively or formally abandons the project or fails to diligently pursue the financing commitment(s).
     The 2002 DOE-USEC Agreement provides DOE with specific remedies if USEC fails to meet a milestone that would materially impact USEC’s ability to begin commercial operations of the American Centrifuge Plant on schedule. These remedies could include terminating the 2002 DOE-USEC Agreement, revoking USEC’s access to DOE’s U.S. centrifuge technology that USEC requires for the success of the American Centrifuge project and requiring USEC to transfer its rights in the American Centrifuge technology and facilities to DOE, and requiring USEC to reimburse DOE for certain costs associated with the American Centrifuge project. DOE could also recommend that USEC be removed as the sole U.S. Executive Agent under the Megatons-to-Megawatts program, which could reduce or terminate USEC’s access to Russian LEU. Any of these actions could have a material adverse impact on USEC’s business.
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     Project Funding
     USEC needs to raise a significant amount of additional capital to continue funding and to complete the American Centrifuge Plant. USEC does not believe public market financing for a large capital project such as American Centrifuge is available given current financial market conditions. In July 2008, USEC applied to the DOE Loan Guarantee Program as the path for obtaining $2 billion in debt financing to complete the American Centrifuge Plant. Areva, a company majority owned by the French government, also applied for funding under this program and is also being considered by DOE. USEC is seeking a selection of its project by DOE in the short term, followed by an expeditious funding commitment and financial closing. However, USEC has no assurance that its project will be selected to move forward in the program, and if USEC is selected, it could still take an extended period for the loan guarantee and funding to be finalized. Accordingly, USEC has initiated steps to conserve cash and reduce the planned escalation of project construction and machine manufacturing activities until USEC gains greater clarity on potential funding for the project through the DOE Loan Guarantee Program. In addition, on a parallel path, USEC continues to evaluate potential third-party investment.
     Without a DOE loan guarantee or other financing and without taking into account USEC’s plans to slow down project spending in 2009, USEC anticipates that its cash, expected internally generated cash flow from operations and available borrowings under its revolving credit facility would be sufficient to meet its cash needs for approximately 6-9 months under the baseline budget and schedule. Taking into account USEC’s plans to slow down project spending, USEC anticipates that its liquidity will be sufficient beyond this period. If USEC determines that a loan guarantee or alternative financing is not forthcoming or available in the near term, USEC will take additional steps to implement further project spending reductions to maintain sufficient liquidity for at least twelve months. However, additional funds may be necessary sooner than USEC currently anticipates if USEC is not successful in its efforts to conserve cash or in the event of increases in the cost of the American Centrifuge project, unanticipated prepayments to suppliers, increases in financial assurance, unanticipated costs under the Russian Contract, increases in power costs or any shortfall in USEC’s estimated levels of operating cash flow, or to meet other unanticipated expenses.
Legal Matters
     DOE Contract Services Matter
     The U.S. Department of Justice (“DOJ”) asserted in a letter to USEC dated July 10, 2006 that DOE may have sustained damages in an amount that exceeds $6.9 million under USEC’s contract with DOE for the supply of cold standby services at the Portsmouth GDP. DOJ indicated that it was assessing possible violations of the Civil False Claims Act (“FCA”), which allows for treble damages and civil penalties, and related claims in connection with invoices submitted under that contract. USEC responded to DOJ’s letter in September 2006, stating that the government does not have a legitimate basis for asserting any FCA or related claims under the cold standby contract, and has been cooperating with DOJ and the DOE Office of Investigations with respect to their inquiries into this matter. In a supplemental presentation by DOJ and DOE on October 18, 2007, DOJ identified revised assertions of alleged overcharges of at least $14.6 million on the cold standby and two other cost-type contracts, again potentially in violation of the FCA. USEC has responded to these assertions and has provided several follow-up responses to DOJ and DOE in response to their requests for additional data and analysis. USEC believes that the DOJ and DOE analyses are significantly flawed, and no loss has been accrued. USEC intends to defend vigorously any FCA or related claim that might be asserted against it. As part of USEC’s continuing discussions with DOJ, USEC and DOJ have agreed several times to extend the statute of limitations for this matter, most recently to April 10, 2009.
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     Environmental Matter
     Under a cleanup agreement with the Environmental Protection Agency (“EPA”), USEC removed certain material from a site in South Carolina previously operated by Starmet CMI, one of USEC’s former contractors, that was attributable to quantities of depleted uranium USEC had sent there under a 1998 contract. In June 2007, USEC was contacted by the EPA concerning costs incurred by the EPA for additional cleanup at the Starmet site. In January 2009, pursuant to the terms of a September 2008 settlement agreement, USEC paid the EPA $1.0 million for the share of additional cleanup costs allocated to USEC in resolution of this matter. At this time, the EPA has completed its actions at the site and USEC is not aware of any further claims associated with the site.
     Other Legal Matters
     USEC is subject to various other legal proceedings and claims, either asserted or unasserted, which arise in the ordinary course of business. While the outcome of these claims cannot be predicted with certainty, USEC does not believe that the outcome of any of these legal matters will have a material adverse effect on its results of operations or financial condition.
Lease Commitments
     Operating costs incurred under the operating leases with DOE for the Paducah, Piketon, and Oak Ridge facilities, and leases for office space and equipment amounted to $9.2 million in 2008, $8.3 million in 2007 and $9.1 million in 2006. Future estimated minimum lease payments and expected lease administration payments follow (in millions):
 	 	 	 	 	
2009	 	$	6.7	 	
2010	 	 	5.8	 	
2011	 	 	5.3	 	
2012	 	 	3.5	 	
2013	 	 	3.3	 	
Thereafter	 	 	29.2	 	
 	 	 	 	
 	 	$	53.8	 	
 	 	 	 	
     Except as provided in the 2002 DOE-USEC Agreement, USEC has the right to extend the lease for the GDPs indefinitely and may terminate the lease in its entirety or with respect to one of the plants at any time upon two years’ notice.
     The initial term of the American Centrifuge Plant lease was through June 30, 2009, and on February 2, 2009, USEC renewed it for an additional term of five years through June 30, 2014. USEC has the option to extend the lease term for additional five-year terms ending in 2043. Thereafter, USEC has the right to extend the American Centrifuge Plant lease for up to an additional 20 years, through 2063, if it agrees to demolish the existing buildings leased to USEC after the lease term expires. USEC has the option, with DOE’s consent, to expand the leased property to meet its needs until the earlier of September 30, 2013 or the expiration or termination of the GDP lease. USEC may terminate the American Centrifuge Plant lease upon three years’ notice. DOE may terminate the lease for default, including default under the 2002 DOE-USEC Agreement.
     USEC has office space and equipment leases for our corporate headquarters in Bethesda, Maryland through November 2016, for our NAC operations in Norcross, Georgia through February 2012, and for a Washington, D.C. office through June 2011.
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DOE Technology License
     USEC has a non-exclusive license in DOE inventions that pertain to enriching uranium using gas centrifuge technology. The license agreement with DOE provides for annual royalty payments based on a varying percentage (1% up to 2%) of USEC’s annual revenues from sales of the SWU component of LEU produced by USEC at the American Centrifuge Plant and any other facility using DOE centrifuge technology. There is a minimum annual royalty payment of $100,000 and the maximum cumulative royalty over the life of the license is $100 million.
17. REVENUE BY GEOGRAPHIC AREA, MAJOR CUSTOMERS AND SEGMENT INFORMATION
     Revenue attributed to domestic and foreign customers, including customers in a foreign country representing 10% or more of total revenue, follows (in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
United States	 	$	1,212.5	 	 	$	1,310.6	 	 	$	1,109.5	 	
Foreign:	 	 	 	 	 	 	 	 	 	 	 	 	
Japan	 	 	242.6	 	 	 	274.7	 	 	 	389.8	 	
Other	 	 	159.5	 	 	 	342.7	 	 	 	349.3	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	402.1	 	 	 	617.4	 	 	 	739.1	 	
 	 	 	 	 	 	 	 	 	 	
 	 	$	1,614.6	 	 	$	1,928.0	 	 	$	1,848.6	 	
 	 	 	 	 	 	 	 	 	 	
     USEC’s 10 largest utility customers represented 57% of revenue and USEC’s three largest utility customers represented 30% of revenue in 2008. Revenue from two domestic customers, Exelon Corporation and Entergy Corporation, each represented more than 10%, but less than 15%, of revenue in 2008. Revenue from U.S. government contracts represented 12% of revenue in 2008, 9% of revenue in 2007 and 10% of revenue in 2006. No other customer represented more than 10% of revenue.
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     USEC has two reportable segments measured and presented through the gross profit line of the income statement: the low enriched uranium (“LEU”) segment with two components, separative work units (“SWU”) and uranium, and the U.S. government contracts segment. The LEU segment is USEC’s primary business focus and includes sales of the SWU component of LEU, sales of both SWU and uranium components of LEU, and sales of uranium. The U.S. government contracts segment includes work performed for DOE and DOE contractors at the Portsmouth and Paducah GDPs, as well as nuclear energy services and technologies provided by NAC. Gross profit is USEC’s measure for segment reporting. Intersegment sales were less than $0.1 million in each of 2008, 2007 and 2006 and have been eliminated in consolidation.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
 	 	(millions)	 	
Revenue	 	 	 	 	 	 	 	 	 	 	 	 	
LEU segment:	 	 	 	 	 	 	 	 	 	 	 	 	
Separative work units	 	$	1,175.5	 	 	$	1,570.5	 	 	$	1,337.4	 	
Uranium	 	 	217.1	 	 	 	163.5	 	 	 	316.7	 	
 	 	 	 	 	 	 	 	 	 	
 	 	 	1,392.6	 	 	 	1,734.0	 	 	 	1,654.1	 	
U.S. government contracts segment	 	 	222.0	 	 	 	194.0	 	 	 	194.5	 	
 	 	 	 	 	 	 	 	 	 	
 	 	$	1,614.6	 	 	$	1,928.0	 	 	$	1,848.6	 	

Segment Gross Profit	 	 	 	 	 	 	 	 	 	 	 	 	
LEU segment	 	$	190.4	 	 	$	260.4	 	 	$	304.9	 	
U.S. government contracts segment	 	 	38.4	 	 	 	27.1	 	 	 	32.0	 	
 	 	 	 	 	 	 	 	 	 	
Gross profit	 	 	228.8	 	 	 	287.5	 	 	 	336.9	 	
Advanced technology costs	 	 	110.2	 	 	 	127.3	 	 	 	105.5	 	
Selling, general, and administrative	 	 	54.3	 	 	 	45.3	 	 	 	48.8	 	
Other, net	 	 	—	 	 	 	—	 	 	 	3.9	 	
 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	64.3	 	 	 	114.9	 	 	 	178.7	 	
Interest (income) expense, net	 	 	(7.4	)	 	 	(16.9	)	 	 	8.3	 	
 	 	 	 	 	 	 	 	 	 	
Income before income taxes	 	$	71.7	 	 	$	131.8	 	 	$	170.4	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
 	 	(millions)	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	 	
LEU segment	 	$	2,997.7	 	 	$	3,036.4	 	 	$	1,800.1	 	
U.S. government contracts segment	 	 	57.6	 	 	 	51.4	 	 	 	61.3	 	
 	 	 	 	 	 	 	 	 	 	
 	 	$	3,055.3	 	 	$	3,087.8	 	 	$	1,861.4	 	
 	 	 	 	 	 	 	 	 	 	
     USEC’s long-term or long-lived assets include property, plant and equipment and other assets reported on the balance sheet at December 31, 2008, all of which were located in the United States.
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18. QUARTERLY FINANCIAL DATA (Unaudited)
     The following table summarizes quarterly and annual results of operations (in millions, except per share data):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	March 31,	 	 	June 30,	 	 	Sept. 30,	 	 	Dec. 31,	 	 	Year	 	
 	 	2008	 	 	2008	 	 	2008	 	 	2008	 	 	2008	 	
Revenue	 	$	343.3	 	 	$	249.0	 	 	$	590.4	 	 	$	431.9	 	 	$	1,614.6	 	
Cost of sales	 	 	304.5	 	 	 	185.5	 	 	 	542.0	 	 	 	353.8	 	 	 	1,385.8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	 	38.8	 	 	 	63.5	 	 	 	48.4	 	 	 	78.1	 	 	 	228.8	 	
Advanced technology costs	 	 	23.9	 	 	 	28.2	 	 	 	29.1	 	 	 	29.0	 	 	 	110.2	 	
Selling, general and administrative	 	 	12.0	 	 	 	16.3	 	 	 	12.4	 	 	 	13.6	 	 	 	54.3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	2.9	 	 	 	19.0	 	 	 	6.9	 	 	 	35.5	 	 	 	64.3	 	
Interest expense	 	 	6.3	 	 	 	5.2	 	 	 	4.0	 	 	 	1.8	 	 	 	17.3	 	
Interest (income)	 	 	(10.8	)	 	 	(6.0	)	 	 	(4.5	)	 	 	(3.4	)	 	 	(24.7	)	
Provision (benefit) for income taxes	 	 	3.0	 	 	 	9.0	 	 	 	(1.0	)	 	 	12.0	 	 	 	23.0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	4.4	 	 	$	10.8	 	 	$	8.4	 	 	$	25.1	 	 	$	48.7	 	

Net income per share — basic	 	$	.04	 	 	$	.10	 	 	$	.08	 	 	$	.23	 	 	$	.44	 	
Net income per share — diluted	 	$	.04	(a)	 	$	.08	 	 	$	.06	 	 	$	.16	 	 	$	.35	 	
Weighted average number of shares outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	109.9	 	 	 	110.6	 	 	 	110.8	 	 	 	110.8	 	 	 	110.6	 	
Diluted	 	 	110.2	(a)	 	 	158.7	 	 	 	158.9	 	 	 	158.9	 	 	 	158.7	 	

 	 	March 31,	 	 	June 30,	 	 	Sept. 30,	 	 	Dec. 31,	 	 	Year	 	
 	 	2007	 	 	2007	 	 	2007	 	 	2007	 	 	2007	 	
Revenue	 	$	465.0	 	 	$	211.1	 	 	$	634.7	 	 	$	617.2	 	 	$	1,928.0	 	
Cost of sales	 	 	391.8	 	 	 	183.4	 	 	 	522.7	 	 	 	542.6	 	 	 	1,640.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross profit	 	 	73.2	 	 	 	27.7	 	 	 	112.0	 	 	 	74.6	 	 	 	287.5	 	
Advanced technology costs	 	 	33.7	 	 	 	35.6	 	 	 	30.8	 	 	 	27.2	 	 	 	127.3	 	
Selling, general and administrative	 	 	12.5	 	 	 	11.5	 	 	 	9.0	 	 	 	12.3	 	 	 	45.3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	27.0	 	 	 	(19.4	)	 	 	72.2	 	 	 	35.1	 	 	 	114.9	 	
Interest expense	 	 	3.5	 	 	 	2.4	 	 	 	3.3	 	 	 	7.7	 	 	 	16.9	 	
Interest (income)	 	 	(9.9	)	 	 	(7.9	)	 	 	(3.9	)	 	 	(12.1	)	 	 	(33.8	)	
Provision (benefit) for income taxes	 	 	(5.9	)	 	 	(0.5	)	 	 	27.2	 	 	 	14.4	 	 	 	35.2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	39.3	 	 	$	(13.4	)	 	$	45.6	 	 	$	25.1	 	 	$	96.6	 	

Net income (loss) per share — basic	 	$	.45	 	 	$	(.15	)	 	$	.52	 	 	$	.22	 	 	$	1.04	 	
Net income (loss) per share — diluted	 	$	.45	 	 	$	(.15	)	 	$	.51	 	 	$	.18	 	 	$	.94	 	
Weighted average number of shares outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	86.8	 	 	 	87.1	 	 	 	87.9	 	 	 	110.1	 	 	 	93.0	 	
Diluted	 	 	87.2	 	 	 	87.1	 	 	 	89.8	 	 	 	158.4	 	 	 	105.8	 	

(a)	 	No effect of the convertible notes was recognized since the effect of full conversion was antidilutive.	
     The calculation of net income per share and average number of shares outstanding on a dilutive basis for the years ended December 31, 2008, 2007 and 2006 is provided in note 14. No dilutive effect is recognized in periods in which a net loss has occurred.
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GLOSSARY
2002 DOE-USEC Agreement — An agreement in which USEC and DOE made long-term commitments directed at resolving issues related to the stability and security of the domestic uranium enrichment industry (such agreement, as amended, the “2002 DOE-USEC Agreement”). This agreement provides that USEC will develop, demonstrate and deploy the American Centrifuge technology in accordance with 15 milestones.
American Centrifuge — An advanced uranium enrichment technology based on the proven workable U.S. centrifuge technology developed by DOE in the mid-1980s.
American Centrifuge Demonstration Facility — Demonstration facility in Piketon, Ohio where USEC has installed and is operating centrifuge machines as part of its Lead Cascade test program to demonstrate the American Centrifuge technology.
American Centrifuge Plant (“ACP”) — USEC’s planned commercial uranium enrichment facility using centrifuge technology. USEC plans to install thousands of centrifuge machines and operate the facility in the gas centrifuge enrichment plant buildings in Piketon, Ohio owned by DOE.
Assay — The concentration of U235 expressed by percentage of weight in a given quantity of uranium ore, uranium hexafluoride, uranium oxide or other uranium form. An assay of 3% to 5% U 235  is required for most commercial nuclear power plants.
Centrifuge — A technology for enriching uranium by spinning uranium hexafluoride at high speed and using centrifugal force to separate the heavier U 238  from the lighter U 235 .
CERCLA — The Comprehensive Environmental Response, Compensation, and Liability Act (42 U.S.C. 9601 et seq.), a federal law passed in 1980 by the Superfund Amendments and Reauthorization Act. The act created a government trust fund, commonly known as Superfund, to investigate and clean up abandoned or uncontrolled hazardous waste sites.
Depleted Uranium — Uranium hexafluoride that is depleted in the U235 isotope as a result of the enrichment process.
DOC — The U.S. Department of Commerce.
DOE — The U.S. Department of Energy.
Downblending —The diluting or mixing of highly enriched uranium with depleted or natural uranium to produce low enriched uranium with a concentration of U 235  of less than 5% for use in commercial nuclear reactors.
Enrichment — The step in the nuclear fuel cycle that increases the weight percent of U235 relative to U238 in order to make uranium usable as a fuel for nuclear power reactors.
EPA — The U.S. Environmental Protection Agency.
Freon — The trade name for a group of chlorofluorocarbons (CFCs) used primarily as a refrigerant. The Paducah GDP uses Freon as the primary process coolant. The production of Freon in the United States was terminated in 1995.
Gaseous Diffusion — A means of enriching uranium hexafluoride, which is heated to a gas and passed repeatedly through a porous barrier to separate the heavier U 238  from the lighter U 235 . The gas that diffuses through the barrier becomes increasingly more concentrated or enriched.
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Highly Enriched Uranium — Uranium enriched in the isotope U235 to an assay equal to or greater than 20%.
Isotope — One or more atoms of an element having the same atomic number but different mass number.
Lead Cascade — An array of full-size centrifuge machines operating in a closed-loop configuration, from which samples are withdrawn for testing purposes and the enriched and depleted uranium streams are recombined into feed material.
Low Enriched Uranium (“LEU”) — Uranium enriched in the isotope U235 to an assay of less than 20%. Commercial grade LEU typically has an assay of 3% to 5% and is used as fuel in nuclear reactors for the generation of electric power.
Megatons to Megawatts — The Russian Contract.
Megawatt (“MW”) — A megawatt equals 1,000 kilowatts. One megawatt-hour represents one hour of electricity consumption at a constant rate of 1 MW.
Natural Uranium — Uranium that has not been enriched or depleted in the isotope U235.
NMMSS — The Nuclear Materials Management and Safeguards System of the DOE and NRC.
NRC — The U.S. Nuclear Regulatory Commission.
Paducah GDP — The Paducah gaseous diffusion plant in Paducah, Kentucky.
Portsmouth GDP — The Portsmouth gaseous diffusion plant in Piketon, Ohio.
Price-Anderson Act — Price-Anderson Nuclear Industry Indemnities Act of 1957, as amended, provides a system of indemnification for certain legal liability resulting from a nuclear incident in connection with contractual activity for DOE.
Russian Contract — Contract, dated January 14, 1994, between USEC and TENEX to implement the Agreement between the United States and the Russian Federation Concerning the Disposition of Highly Enriched Uranium Extracted from Nuclear Weapons. Under the contract, USEC serves as Executive Agent for the United States Government, and TENEX serves as agent for the State Atomic Energy Corporation (“Rosatom”), Executive Agent for the Russian government.
Russian Suspension Agreement — A 1992 agreement between the U.S. Commerce Department and the Russian Ministry of Atomic Energy suspending an antidumping investigation against imports of Russian uranium products that had resulted in preliminary duties in excess of 100% of the value of the imports.
Separative Work Unit (“SWU”) — The standard measure of enrichment in the uranium enrichment industry is a separative work unit or SWU. A SWU represents the effort that is required to transform a given amount of natural uranium into two streams of uranium, one enriched in the U 235  isotope and the other depleted in the U 235  isotope, and is measured using a standard formula based on the physics of uranium enrichment. The amount of enrichment contained in LEU under this formula is commonly referred to as the SWU component.
Technetium — A byproduct from the operation of nuclear reactors and a contaminant in natural uranium.
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TENEX — OAO Techsnabexport, agent for the State Atomic Energy Corporation (“Rosatom”), Executive Agent for the Russian government under the Agreement between the United States and the Russian Federation Concerning the Disposition of Highly Enriched Uranium Extracted from Nuclear Weapons.
TVA — Tennessee Valley Authority, a federally-chartered corporation that supplies electric power to the Paducah gaseous diffusion plant.
Underfeeding — A mode of operation that uses or feeds less uranium but requires more SWU in the enrichment process, which requires more electric power.
Uranium — One of the heaviest elements found in nature. Approximately 993 of every 1000 uranium atoms are U238 while approximately seven atoms are U 235 , which can be made to split, or fission, and generate heat energy.
UF6 — See Uranium Hexafluoride.
Uranium Hexafluoride (“UF6”) — Uranium chemical compound produced from converting natural uranium oxide into a fluoride at a conversion plant. Uranium hexafluoride is the feed material for uranium enrichment plants.
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EXHIBIT INDEX
 	 	 	
Exhibit No.	 	Description	
3.1	 	Certificate of Incorporation of USEC Inc., as amended, incorporated by reference to Exhibit 3.1 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (Commission file number 1-14287).	
 	 	 	
3.3	 	Amended and Restated Bylaws of USEC Inc., dated December 13, 2007, incorporated by reference to Exhibit 3.1 of the Current Report on Form 8-K filed on December 13, 2007 (Commission file number 1-14287).	
 	 	 	
4.1	 	Indenture, dated January 15, 1999, between USEC Inc. and First Union National Bank, incorporated by reference to Exhibit 4.2 of the Annual Report on Form 10-K for the fiscal year ended June 30, 1999 (Commission file number 1-14287).	
 	 	 	
4.2	 	Rights Agreement, dated April 24, 2001, between USEC Inc. and Fleet National Bank, as Rights Agent, including the form of Certificate of Designation, Preferences and Rights as Exhibit A, the form of Rights Certificates as Exhibit B and the Summary of Rights as Exhibit C, incorporated by reference to Exhibit 4.3 of the Registration Statement on Form 8-A filed April 24, 2001 (Commission file number 1-14287).	
 	 	 	
4.3	 	Indenture dated September 28, 2007, between USEC Inc. and Wells Fargo Bank, N.A., incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed on September 28, 2007 (Commission file number 1-14287).	
 	 	 	
10.1	 	Lease Agreement between the United States Department of Energy (“DOE”) and the United States Enrichment Corporation, dated as of July 1, 1993, including notice of exercise of option to renew, incorporated by reference to Exhibit 10.1 of the Registration Statement on Form S-1, filed June 29, 1998 (Commission file number 333-57955).	
 	 	 	
10.2	 	Supplemental Agreement No. 1 to the Lease Agreement between DOE and the United States Enrichment Corporation, dated as of December 7, 2006, incorporated by reference to Exhibit 10.2 of the Annual Report on Form 10-K for the year ended December 31, 2006 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to confidential treatment under Rule 24b-2).	
 	 	 	
10.3	 	Contract between United States Enrichment Corporation, Executive Agent of the United States of America, and AO Techsnabexport, Executive Agent of the Ministry of Atomic Energy, Executive Agent of the Russian Federation, dated January 14, 1994, as amended (“Russian Contract”) incorporated by reference to Exhibit 10.17 of the Registration Statement on Form S-1, filed June 29, 1998 (Commission file number 333-57955).	
 	 	 	
10.4	 	Amendment No. 11, dated June 1998, to Russian Contract, incorporated by reference to Exhibit 10.4 of the Annual Report on Form 10-K for the year ended December 31, 2005 (Commission file number 1-14287).	
 	 	 	
10.5	 	Amendment No. 12, dated March 4, 1999, to Russian Contract, incorporated by reference to Exhibit 10.36 of the Annual Report on Form 10-K for the fiscal year ended June 30, 1999 (Commission file number 1-14287).	
 	 	 	
10.6	 	Amendment No. 13, dated November 11, 1999, to Russian Contract, incorporated by reference to Exhibit 10.6 of the Annual Report on Form 10-K for the year ended December 31, 2005 (Commission file number 1-14287).	
 	 	 	
10.7	 	Amendment No. 14, dated October 27, 2000, to Russian Contract, incorporated by reference to Exhibit 10.7 of the Annual Report on Form 10-K for the year ended December 31, 2005 (Commission file number 1-14287).	
 	 	 	
10.8	 	Amendment No. 15, dated January 18, 2001, to Russian Contract, incorporated by reference to Exhibit 10.8 of the Annual Report on Form 10-K for the year ended December 31, 2005 (Commission file number 1-14287).	
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Exhibit No.	 	Description	
10.9	 	Amendment No. 17, dated December 5, 2007, to Russian Contract. (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
 	 	 	
10.10	 	Memorandum of Agreement, dated April 6, 1998, between the Office of Management and Budget and United States Enrichment Corporation relating to post-privatization liabilities, incorporated by reference to Exhibit 10.18 of the Registration Statement on Form S-1, filed June 29, 1998 (Commission file number 333-57955).	
 	 	 	
10.11	 	Memorandum of Agreement entered into as of April 18, 1997, between the United States, acting by and through the United States Department of State and the DOE, and United States Enrichment Corporation for United States Enrichment Corporation to serve as the United States Government’s Executive Agent under the Agreement between the United States and the Russian Federation concerning the disposal of highly enriched uranium extracted from nuclear weapons, incorporated by reference to Exhibit 10.25 of the Registration Statement on Form S-1/A, filed July 21, 1998 (Commission file number 333-57955).	
 	 	 	
10.12	 	Power Contract between Tennessee Valley Authority and United States Enrichment Corporation, dated July 11, 2000 (“TVA Power Contract”), incorporated by reference to Exhibit 10.45 of the Annual Report on Form 10-K for the fiscal year ended June 30, 2000 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to confidential treatment under Rule 24b-2).	
 	 	 	
10.13	 	Supplement No. 1 dated March 2, 2006 to TVA Power Contract, incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to confidential treatment under Rule 24b-2).	
 	 	 	
10.14	 	Supplement No. 2 dated March 2, 2006 to TVA Power Contract, incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to confidential treatment under Rule 24b-2).	
 	 	 	
10.15	 	Amendatory Agreement (Supplement No. 3) dated April 3, 2006 to TVA Power Contract, incorporated by reference to Exhibit 10.4 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to confidential treatment under Rule 24b-2).	
 	 	 	
10.16	 	Amendatory Agreement (Supplement No. 4) dated June 1, 2007 to Power Contract between Tennessee Valley Authority and United States Enrichment Corporation, incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
 	 	 	
10.17	 	Supplement No. 5 dated June 2, 2008 to TVA Power Contract, incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to confidential treatment under Rule 24b-2).	
 	 	 	
10.18	 	Agreement, dated June 17, 2002, between DOE and USEC Inc., incorporated by reference to Exhibit 10.54 of the current report on Form 8-K filed June 21, 2002 (Commission file number 1-14287).	
 	 	 	
10.19	 	Modification 1 to Agreement dated June 17, 2002 between DOE and USEC Inc., dated August 20, 2002, incorporated by reference to Exhibit 10.15 of the Annual Report on Form 10-K for the year ended December 31, 2005 (Commission file number 1-14287).	
 	 	 	
10.20	 	Modification No. 2 dated January 12, 2009, to Agreement dated June 17, 2002 between DOE and USEC Inc., incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on January 13, 2009 (Commission file number 1-14287).	
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Exhibit No.	 	Description	
10.21	 	Cooperative Research and Development Agreement, Development of an Economically Attractive Gas Centrifuge Machine and Enrichment Process, by and between UT-Battelle, LLC, under its DOE Contract, and USEC Inc., dated June 30, 2000, Amendment A, dated July 12, 2002, and Amendment B, dated September 11, 2002, incorporated by reference to Exhibit 10.58 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (Commission file number 1-14287).	
 	 	 	
10.22	 	Amendment C to the Cooperative Research and Development Agreement, Development of an Economically Attractive Gas Centrifuge Machine and Enrichment Process, by and between UT-Battelle, LLC, under its DOE Contract, and USEC Inc., dated February 28, 2007, incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (Commission file number 1-14287).	
 	 	 	
10.23	 	Amendment D to the Cooperative Research and Development Agreement, Development of an Economically Attractive Gas Centrifuge Machine and Enrichment Process, by and between UT-Battelle, LLC, under its DOE Contract, and USEC Inc., dated August 10, 2007, incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2007. (Commission file number 1-14287).	
 	 	 	
10.24	 	Amended and Restated Revolving Credit Agreement dated as of August 18, 2005 among USEC Inc., United States Enrichment Corporation, the lenders named therein, JPMorgan Chase Bank, N.A., as administrative and collateral agent, J.P. Morgan Securities, Inc., Merrill Lynch Capital and Goldman Sachs Credit Partners, L.P., as joint book managers and joint lead arrangers, Merrill Lynch Capital and Goldman Sachs Credit Partners, L.P., as co-syndication agents, GMAC Commercial Finance LLC and Wachovia Bank, National Association, as co-documentation agents, and CIT Capital Securities, LLC, as co-agent, incorporated by reference to Exhibit 10.83 of the Current Report on Form 8-K filed on August 23, 2005 (Commission file number 1-14287).	
 	 	 	
10.25	 	First Amendment to Amended and Restated Revolving Credit Agreement dated as of August 18, 2005 among USEC Inc., United States Enrichment Corporation, the lenders named therein, JPMorgan Chase Bank, N.A., as administrative and collateral agent, and the other financial institutions named therein, dated March 6, 2006, incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 (Commission file number 1-14287).	
 	 	 	
10.26	 	Second Amendment to Amended and Restated Revolving Credit Agreement among USEC Inc., United States Enrichment Corporation, the lenders named therein, JPMorgan Chase Bank, N.A., as administrative and collateral agent, and the other financial institutions named therein, dated October 16, 2006, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on October 19, 2006 (Commission file number 1-14287).	
 	 	 	
10.27	 	Third Amendment dated September 21, 2007 to the Amended and Restated Revolving Credit Agreement, dated as of August 18, 2005, among USEC Inc., United States Enrichment Corporation, the lenders named therein, JPMorgan Chase Bank, N.A., as administrative and collateral agent, and the other financial institutions named therein, incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on September 25, 2007 (Commission file number 1-14287).	
 	 	 	
10.28	 	Amended and Restated Omnibus Pledge and Security agreement dated as of August 18, 2005 by USEC Inc., United States Enrichment Corporation, NAC Holding Inc. and NAC International Inc., in favor of JPMorgan Chase Bank, N.A., as administrative and collateral agent for the lenders, incorporated by reference to Exhibit 10.84 of the Current Report on Form 8-K filed on August 23, 2005 (Commission file number 1-14287).	
 	 	 	
10.29	 	License dated December 7, 2006 between the United States of America, as represented by DOE, as licensor, and USEC Inc., as licensee, incorporated by reference to Exhibit 10.34 of the Annual Report on Form 10-K for the year ended December 31, 2006 (Commission file number 1-14287).	
 	 	 	
10.30	 	Contract dated June 25, 2007 between USEC Inc. and BWXT Services, Inc., incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
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Exhibit No.	 	Description	
10.31	 	Contract dated as of August 16, 2007 between USEC Inc., ATK Space Systems Inc., a subsidiary of Alliant Techsystems, and Hexcel Corporation, incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
 	 	 	
10.32	 	Contract dated August 30, 2007 between USEC Inc. and Major Tool and Machine, Inc., incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
 	 	 	
10.33	 	Contract dated April 24, 2008 between Fluor Enterprises, as agent for USEC Inc., and Teledyne Brown Engineering, Inc., incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
 	 	 	
10.34	 	Amended and Restated Design, Engineering, Procurement, Construct ion and Construction Management Agreement for the American Centrifuge Plant between USEC Inc. and Fluor Enterprises, Inc., entered into September 24, 2008, effective as of January 1, 2008, incorporated by reference to Exhibit 10.4 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (Commission file number 1-14287). (Certain information has been omitted and filed separately pursuant to a request for confidential treatment under Rule 24b-2).	
 	 	 	
10.35	 	Form of Director and Officer Indemnification Agreement, incorporated by reference to Exhibit 10.25 of the Registration Statement on Form S-1/A, filed July 21, 1998 (Commission file number 333-57955). (b)	
 	 	 	
10.36	 	Form of Change in Control Agreement with executive officers. (a)(b)	
 	 	 	
10.37	 	Form of Change in Control Agreement with senior executive officers. (a)(b)	
 	 	 	
10.38	 	USEC Inc. 1999 Equity Incentive Plan, incorporated by reference to Exhibit 10.35 of the Registration Statement on Form S-8, No. 333-71635, filed February 2, 1999. (b)	
 	 	 	
10.39	 	First Amendment to the USEC Inc. 1999 Equity Incentive Plan, incorporated by reference to Annex B of Schedule 14A filed March 31, 2004, with respect to the 2004 annual meeting of shareholders (Commission file number 1-14287). (b)	
 	 	 	
10.40	 	Second Amendment to the USEC Inc. 1999 Equity Incentive Plan, dated November 1, 2007, incorporated by reference to Exhibit 10.46 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
 	 	 	
10.41	 	Form of Employee Nonqualified Stock Option Agreement, incorporated by reference to Exhibit 4.4 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (Commission file number 1-14287). (b)	
 	 	 	
10.42	 	Form of Employee Restricted Stock Award Agreement (stock in lieu of annual incentive), incorporated by reference to Exhibit 4.6 of the Annual Report on Form 10-K for the year ended December 31, 2004 (Commission file number 1-14287). (b)	
 	 	 	
10.43	 	Form of Employee Restricted Stock Award Agreement (three year vesting), incorporated by reference to Exhibit 4.7 of the Annual Report on Form 10-K for the year ended December 31, 2004 (Commission file number 1-14287). (b)	
 	 	 	
10.44	 	Form of Non-Employee Director Nonqualified Stock Option Agreement, incorporated by reference to Exhibit 4.8 of the Annual Report on Form 10-K for the year ended December 31, 2004 (Commission file number 1-14287). (b)	
 	 	 	
10.45	 	Form of Non-Employee Director Restricted Stock Award Agreement — Founder’s Stock and Incentive Stock, incorporated by reference to Exhibit 4.9 of the Annual Report on Form 10-K for the year ended December 31, 2004 (Commission file number 1-14287). (b)	
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Exhibit No.	 	Description	
10.46	 	Form of Non-Employee Director Restricted Stock Award Agreement — Annual Retainers and Meeting Fees, incorporated by reference to Exhibit 4.10 of the Annual Report on Form 10-K for the year ended December 31, 2004 (Commission file number 1-14287). (b)	
 	 	 	
10.47	 	Form of Non-Employee Director Restricted Stock Unit Award Agreement (Annual Retainers and Meeting Fees), incorporated by reference to Exhibit 10.53 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
 	 	 	
10.48	 	Form of Non-Employee Director Restricted Stock Unit Award Agreement (Incentive Awards) incorporated by reference to Exhibit 10.54 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
 	 	 	
10.49	 	USEC Inc. Pension Restoration Plan, as amended and restated, dated November 1, 2007 incorporated by reference to Exhibit 10.55 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
 	 	 	
10.50	 	First Amendment, dated August 1, 2008, to USEC Inc. Pension Restoration Plan, as amended and restated, dated November 1, 2007, incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (Commission file number 1-14287). (b)	
 	 	 	
10.51	 	USEC Inc. 401(k) Restoration Plan, incorporated by reference to Exhibits 10.41(a) through (f) of the Quarterly Report on Form 10-Q for the quarter ended December 31, 1999 (Commission file number 1-14287). (b)	
 	 	 	
10.52	 	USEC Inc. 1999 Supplemental Executive Retirement Plan, as amended and restated, dated August 1, 2008, incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (Commission file number 1-14287). (b)	
 	 	 	
10.53	 	Summary Sheet for 2007 Non-Employee Director Compensation, incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (Commission file number 1-14287). (b)	
 	 	 	
10.54	 	Summary Sheet for 2008 Non-Employee Director Compensation, incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 (Commission file number 1-14287). (b)	
 	 	 	
10.55	 	Summary of Compensation Arrangement with James R. Mellor, incorporated by reference to Exhibit 10.61 of the Annual Report on Form 10-K for the year ended December 31, 2006 (Commission file number 1-14287). (b)	
 	 	 	
10.56	 	Summary of 2008 Annual Performance Objectives for Named Executive Officers, incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (Commission file number 1-14287). (b)	
 	 	 	
10.57	 	USEC Inc. 2006 Supplemental Executive Retirement Plan, as amended and restated, dated November 1, 2007, incorporated by reference to Exhibit 10.64 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
 	 	 	
10.58	 	Executive Incentive Plan Summary Plan Description, incorporated by reference to Exhibit 10.1 of the current report on Form 8-K filed on April 28, 2006 (Commission file number 1-14287). (b)	
 	 	 	
10.59	 	USEC Inc. Executive Severance Plan dated August 1, 2008, incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (Commission file number 1-14287). (b)	
 	 	 	
10.60	 	USEC Inc. Executive Deferred Compensation Plan, dated November 1, 2007 incorporated by reference to Exhibit 10.67 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
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Exhibit No.	 	Description	
10.61	 	USEC Inc. Director Deferred Compensation Plan, dated November 1, 2007 incorporated by reference to Exhibit 10.68 of the Annual Report on Form 10-K for the year ended December 31, 2007 (Commission file number 1-14287). (b)	
 	 	 	
21	 	Subsidiaries of USEC Inc. (a)	
 	 	 	
23.1	 	Consent of PricewaterhouseCoopers LLP, independent registered public accounting firm. (a)	
 	 	 	
31.1	 	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a). (a)	
 	 	 	
31.2	 	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a). (a)	
 	 	 	
32	 	Certification of CEO and CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (a)	
 	 	 	
99.1	 	Letter from U.S. Department of State, dated August 23, 2002, in compliance with Rule 0-6 of the Securities Exchange Act of 1934, incorporated by reference to Exhibit 99.4 of the Annual Report on Form 10-K for the fiscal year ended June 30, 2002 (Commission file number 1-14287).	
 	 	 	
99.2	 	Annual CEO Certification dated April 30, 2008, as filed with the New York Stock Exchange. (a)	

(a)	 	Filed herewith	
 	 	 	
(b)	 	Management contracts and compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report.	
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EXHIBIT 10.36
CHANGE IN CONTROL AGREEMENT
     AGREEMENT (this “Agreement”) by and between USEC Inc., a Delaware corporation (the “Company”) and                        (the “Executive”) dated and effective as of                       , ___.
     WHEREAS, the Executive is currently an employee of the Company;
     WHEREAS, the Board of Directors of the Company has determined that it is essential to the best interests of the Company and its shareholders to foster the continued employment of the Executive, notwithstanding the possibility, threat or occurrence of a Change in Control (as defined in Section 1 hereof) of the Company;
     WHEREAS, the Board of Directors of the Company has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of the Executive in the Executive’s assigned duties without distraction in the face of potentially disturbing circumstances arising from any possible Change in Control of the Company; and
     WHEREAS, the Board of Directors of the Company has concluded that the interests of the Company described above can be best satisfied by agreeing to make certain payments to the Executive if the Executive’s employment is terminated during a protected period prior to or following a Change in Control;
     NOW, THEREFORE, the parties hereto hereby agree as follows:
1. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:
     “Affiliate” shall mean (i) any entity that, directly or indirectly, is controlled by the Company, (ii) any entity in which the Company has a significant equity interest and (iii) an affiliate of the Company, as defined in Rule 12b-2 promulgated under Section 12 of the Exchange Act, in each case as determined by the Committee.
     “Board” shall mean the Board of Directors of the Company or, in the case of any subsidiary of the Company, the board of directors, board of control, board of managers or other governing body of such subsidiary.
     “Cause” shall mean any of the following:
     (i) the engaging by the Executive in willful misconduct that is injurious to the Company or its Affiliates;
     (ii) the embezzlement or misappropriation of funds or material property of the Company or its Affiliates by the Executive, or the conviction of the Executive of a felony or the entrance of a plea of guilty or nolo contendere by the Executive to a felony; or

 
     (iii) the willful failure or refusal by the Executive to substantially perform his or her duties or responsibilities that continues after demand for substantial performance is delivered by the Company to the Executive that specifically identifies the manner in which the Company believes the Executive has not substantially performed his or her duties (other than (a) any such failure resulting from the Executive’s incapacity due to Disability, or (b) any such actual or anticipated failure after the issuance of a Notice of Termination by the Executive for Good Reason).
For purposes of this definition, no act, or failure to act, on the Executive’s part shall be considered “willful” unless done, or omitted to be done, by him or her not in good faith and without reasonable belief that his or her action or omission was in the best interest of the Company. Notwithstanding the foregoing, the Executive’s employment shall not be deemed to have been terminated for Cause unless (A) a reasonable notice shall have been given to him or her setting forth in reasonable detail the reasons for the Company’s intentions to terminate for Cause, and if such termination is pursuant to clause (i) or (iii) above and the damage to the Company or its Affiliates is curable, only if the Executive has been provided a period of ten business days from receipt of such notice to cease the actions or inactions, and he or she has not done so; (B) an opportunity shall have been provided for the Executive together with his or her counsel, to be heard before the Board of Directors of the Company; and (C) if such termination is pursuant to clause (i) or (iii) above, delivery shall have been made to the Executive of a Notice of Termination from the Board of Directors of the Company finding that in the good faith opinion of a majority of the non-management members of the Board of Directors of the Company he or she was guilty of conduct set forth in clause (i) or (iii) above, and specifying the particulars thereof in reasonable detail. Any determination of Cause made by the Company in accordance with the foregoing procedure shall be made by the Company, in its sole discretion. Any such determination shall be final and binding on the Executive.
     “Change in Control” shall mean the following and shall be deemed to have occurred if any of the following events shall have occurred:
     (i) any “Person,” as such term is used in Sections 13(d) and 14(d) of the Exchange Act or Persons acting as a group (other than (A) the Company, (B) any trustee or other fiduciary holding securities under an employee benefit plan of the Company, and (C) any corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of Shares), is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company by reason of having acquired such securities during the 12-month period ending on the date of the most recent acquisition (not including any securities acquired directly from the Company or its Affiliates) representing thirty percent (30%) or more of the total voting power of the Company’s then outstanding voting securities;
     (ii) the majority of members of the Company’s Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Company’s Board before the date of the appointment;
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     (iii) there is consummated a merger or consolidation of the Company or any subsidiary of the Company with any other corporation or other entity, resulting in a change described in clauses (i), (ii), (iv), (v), or (vi) of this definition, other than (A) a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving or parent entity) more than sixty percent (60%) of the total voting power of the voting securities of the Company or such surviving or parent entity outstanding immediately after such merger or consolidation or (B) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no Person, directly or indirectly, acquired forty percent (40%) or more of the total voting power of the Company’s then outstanding securities (not including any securities acquired directly from the Company or its Affiliates);
     (iv) a liquidation of the Company involving the sale to any Person or Persons acting as a group of at least forty percent (40%) of the total gross fair market value of all of the assets of the Company immediately before the liquidation;
     (v) the sale or disposition by the Company or any direct or indirect subsidiary of the Company to any Person or Persons acting as a group (other than any subsidiary of the Company) of assets that have a total fair market value equal to forty percent (40%) or more of the total gross fair market value of all of the assets of the Company and its subsidiaries (taken as a whole) immediately before such sale or disposition (or any transaction or related series of transactions having a similar effect), other than a sale or disposition by the Company or any direct or indirect subsidiary of the Company to an entity, at least sixty percent (60%) of the total voting power of the voting securities of which is beneficially owned by shareholders of the Company in substantially the same proportions as their beneficial ownership of the Company immediately prior to such sale;
     (vi) the sale or disposition by the Company or any direct or indirect subsidiary of the Company to any Person or Persons acting as a group (other than any subsidiary of the Company) of a subsidiary or subsidiaries of the Company credited under GAAP with forty percent (40%) or more of the total revenues of the Company and its subsidiaries (taken as a whole) in the current fiscal year or in any of the two most recently completed fiscal years (or any transaction or related series of transactions having a similar effect), other than a sale or disposition by the Company or any direct or indirect subsidiary of the Company to an entity, at least sixty percent (60%) of the total voting power of the voting securities of which is beneficially owned by shareholders of the Company in substantially the same proportions as their beneficial ownership of the Company immediately prior to such sale; or
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     (vii) a change of the kind described in clauses (i), (ii), (iii), or (iv) of this definition with respect to any Material Subsidiary (with such determination made by replacing “Company” with “Material Subsidiary” in each instance in such clauses); provided, however, that for purposes of applying this provision to clause (i) of this definition, a “Change in Control” shall not be deemed to occur solely as a result of a Person or Persons acting as a group becoming the beneficial owner (as determined under clause (i) of this definition) of less than fifty percent (50%) of the ownership interests of a Material Subsidiary, but shall be deemed to occur if such Person or Persons acting as a group thereafter become the beneficial owner (as determined under clause (i) of this definition) of fifty percent (50%) or more of the ownership interests of such Material Subsidiary.
     “Code” shall mean the Internal Revenue Code of 1986, as amended.
     “Committee” shall mean the Compensation Committee of the Company’s Board of Directors.
     “Disability” shall mean that the Executive has become totally and permanently disabled as defined or described in the Company’s long term disability benefit plan applicable to executive officers as in effect at the time the Executive’s disability is incurred.
     “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.
     “Good Reason” shall mean, without the Executive’s express written consent, any of the following, unless such act or failure to act is corrected prior to the Date of Termination specified in the Notice of Termination given in respect thereof:
     (i) the Executive is removed from the Executive’s position (with the Company or any Material Subsidiary) as in effect immediately prior to the start of the Protected Period for any reason other than (A) by reason of death, Disability or Retirement or (B) for Cause; provided that such action results in a material diminution of Executive’s authority, duties or responsibilities with the Company and its subsidiaries, taken as a whole;
     (ii) the Executive is assigned any duties inconsistent in a material respect with the Executive’s position (including status, offices, and reporting relationships with the Company or any Material Subsidiary), authority, duties or responsibilities as in effect immediately prior to the start of the Protected Period (or thereafter if increased) if such assignment results in a material diminution of such Executive’s authority, duties or responsibilities with the Company and its subsidiaries, taken as a whole;
     (iii) the Company materially breaches the agreement under which the Executive provides services;
     (iv) the Executive’s annual base salary or annual bonus opportunity (determined on an aggregate basis for the Company and its subsidiaries) as in effect immediately prior to the start of the Protected Period (or thereafter if higher) is materially reduced (except for across-the-board reductions similarly affecting all senior executives of the Company and of any Material Subsidiary and all senior executives of any Person in control of the Company);
     (v) the failure of the Company to obtain an agreement that materially satisfies Section 9 hereof;
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     (vi) any relocation of the Executive’s principal place of business from its location as of the date immediately preceding the start of the Protected Period, by more than fifty (50) miles; or
     (vii) any purported termination of the Executive’s employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 3(b) hereof, which termination for purposes of this Agreement shall be ineffective.
Notwithstanding the foregoing, a termination shall not be treated as a termination for Good Reason unless the Executive shall have delivered a Notice of Termination stating that the Executive intends to terminate employment for Good Reason within ninety (90) days, and such Termination must occur within two years, of the Executive’s having actual knowledge of the initial occurrence of one or more of such events, provided, in each such event, the Company fails to cure within thirty (30) days of receipt of such Notice of Termination. For purposes of this Agreement, any good faith determination of “Good Reason” or good faith determination of the Company’s failure to cure within the thirty (30) day period made by the Executive shall be conclusive.
     “Material Subsidiary” shall mean any subsidiary of the Company (a) whose total assets represent forty percent (40%) or more of the total gross fair market value of all of the assets of the Company and its subsidiaries (taken as a whole) at any time in the current fiscal year or in any of the two most recently completed fiscal years or (b) credited under GAAP with forty percent (40%) or more of the total revenues of the Company and its subsidiaries (taken as a whole) in the current fiscal year or in any of the two most recently completed fiscal years.
     “Protected Period” shall mean the period that begins upon the earlier of (i) three months before the date of any (and each) Change in Control or (ii) the date the Company or any Material Subsidiary enters into a binding agreement with respect to a Change in Control (subject to customary closing conditions), and ends three years after the date of such Change in Control.
     “Retirement” shall mean the Executive’s Separation from Service initiated by the Executive after attainment by the Executive of age sixty-five (65).
     “Section 409A Penalties” shall have the meaning set forth in Section 14 of this Agreement.
     “Specified Employee” shall mean any person described in Section 409A(a)(2)(B)(i) of the Code and Treasury Regulation Section 1.409A-1(i) as determined from time to time by the Committee in its discretion.
     “Shares” shall mean shares of common stock, $0.10 par value, of the Company, or such other securities of the Company as may be designated by the Committee from time to time.
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     “subsidiary” shall mean, with respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than fifty percent (50%) of the equity or more than fifty percent (50%) of the ordinary voting power or, in the case of a partnership, more than fifty percent (50%) of the general partnership interests are, as of such date, or were, prior to a Change of Control, owned, controlled or held, or (b) that is, or was prior to a Change of Control, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent. For purposes of this paragraph, “Controlled” shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract, or otherwise.
     “Termination of Employment” shall mean and be interpreted in a manner consistent with the definition of “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Code and Treasury Regulation Section 1.409A-1(h). The Company retains the right and discretion to specify, and may specify, whether a Termination of Employment occurs for individuals providing services to the Company immediately prior to an asset purchase transaction in which the Company is the seller, who provide services to a buyer after and in connection with such asset purchase transaction; provided, such specification is made in accordance with the requirements of Treasury Regulation Section 1.409A-1(h)(4).
2. Term of Agreement. The term of this Agreement will commence as of the date hereof (the “Effective Date”) and shall continue in effect until the third anniversary of the Effective Date, unless further extended or sooner terminated as hereinafter provided. Commencing on the first anniversary of the Effective Date, and on each anniversary of such date thereafter (each, an “Anniversary Date”), the term shall automatically be extended for one additional year unless the Board of Directors of the Company gives notice to the Executive, at least two months prior to such Anniversary Date, that it does not wish to extend the term. Notwithstanding the foregoing, upon the occurrence of a Change in Control during the term of this Agreement, this Agreement shall continue in effect for a period of three years from the date of such Change in Control, unless sooner terminated as hereinafter provided.
3. Termination During a Protected Period.
     (a) Upon a Termination of Employment during any Protected Period by the Company without Cause, or by the Executive for Good Reason, the Executive shall be entitled to the benefits provided in Section 4 hereof.
     (b) Notice of Termination. Following a Change in Control (and prior thereto if reasonably anticipated to be within a Protected Period), any purported Termination of Employment by the Company or by the Executive shall be communicated by written Notice of Termination to the other party hereto in accordance with Section 10 hereof. For purposes of this Agreement, a “Notice of Termination” shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon, shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated, and shall specify the Date of Termination. The failure by the Executive or the Company to set forth in the Notice of Termination any fact or circumstance that contributes to a showing of Good Reason or Cause shall not waive any right of the Executive or the Company under this Agreement or preclude the Executive or the Company from asserting such fact or circumstance in enforcing the Executive’s or the Company’s rights under this Agreement.
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     (c) Date of Termination. Following a Change in Control (and prior thereto if reasonably anticipated to be within a Protected Period), “Date of Termination” shall mean the date within the term of the Agreement specified in the Notice of Termination, which shall not be less than thirty (30) nor more than sixty (60) days from the date such Notice of Termination is given (except for a termination pursuant to paragraph (v) of the definition of Good Reason, in which event the date upon which any succession referred to therein becomes effective shall be deemed the Date of Termination, or a Termination of Employment by the Company for Cause, in which event the date such notice is received shall be the Date of Termination).
4. Compensation upon Termination without Cause or for Good Reason. Upon any Termination of Employment of the Executive by the Company without Cause (other than because of death, Disability or Retirement), or any Termination of Employment by the Executive for Good Reason, in any case, during any Protected Period, in lieu of any severance benefits Executive would otherwise be eligible to receive under any employment agreement with the Company or any subsidiary or under the Company’s or any subsidiary’s severance plan, if any, as in effect immediately prior to the earlier of the Change in Control or the Executive’s Termination of Employment, the Executive shall be entitled to the following benefits and payments:
     (a) A cash lump sum payment (payable within ten days of the Date of Termination) of full base salary through the Date of Termination at the rate in effect at the time the Notice of Termination is given or, if higher, at the rate in effect immediately prior to the reduction giving rise (pursuant to clause (iv) of the definition of Good Reason) to such termination, plus all other amounts to which the Executive is entitled under any compensation or benefit plan of the Company or any subsidiary at the time such payments are due under the terms of such plans;
     (b) A cash lump sum payment (payable within ten (10) days of the Date of Termination) equal to two (2) times the sum of the Final Salary and the Final Average Bonus. “Final Salary” means the Executive’s annual base salary as in effect on the Date of Termination or, if higher, the Executive’s annual base salary in effect immediately prior to the reduction giving rise (pursuant to clause (iv) of the definition of Good Reason) to such termination. “Final Average Bonus” means the average of the three most recent annual bonuses paid to Executive prior to the Date of Termination, whether such annual bonuses are paid in the form of cash or in grants of restricted common stock of the Company or restricted stock units under the USEC Inc. Annual Incentive Program (which, under the USEC Inc. Annual Incentive Program, generally vests one (1) year after the date of grant);  provided ,  however , that (i) any annual bonus paid to Executive that was pro-rated or otherwise adjusted because Executive was not employed by the Company or any subsidiary during the entire period to which such bonus related shall be annualized for purposes of the calculation of the Executive’s Final Average Bonus; (ii) if Executive has experienced a change in position that has increased Executive’s annual bonus opportunity (whether or not such change in position is accompanied by a change in title), any annual bonus paid to Executive with respect to a period prior to such change in position shall not be included in the calculation of the Executive’s Final Average Bonus; (iii) if Executive shall not have been paid at least three annual bonuses prior to the Date of Termination that are includable in the calculation of Executive’s Final Average Bonus, then Executive’s Final Average Bonus shall be an amount equal to the average of such lesser number of annual bonuses (or, if just one annual bonus, an amount equal to such bonus); and (iv) if Executive shall not have been paid at least one annual bonus prior to the Date of Termination that is includable in the calculation of Executive’s Final Average Bonus, Executive’s Final Average Bonus shall be an amount equal to Executive’s annual target bonus as in effect on the Date of Termination or, if higher, the Executive’s annual target bonus in effect immediately prior to the reduction giving rise (pursuant to clause (iv) of the definition of Good Reason) to such termination. Final Average Bonus shall not include any amount of cash or equity paid or granted as part of any long term incentive plan or program that the Company in its sole discretion may elect to maintain from time to time;
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     (c) Subject to the Executive’s continued compliance with Section 7 hereof and the limitation in Section 12, life, accident and health insurance benefits substantially similar to those that the Executive was receiving immediately prior to the Change in Control (or thereafter, if higher) until the earlier to occur of (i) the second anniversary of the Date of Termination or (ii) such time as the Executive is covered by comparable programs of a subsequent employer.
     (d) In addition to all other amounts payable under this Section 4, the Executive shall be entitled to receive all benefits payable under any other plan or agreement relating to retirement benefits (including plans or agreements of any successor following a Change in Control) in accordance with the terms of such plan or agreement; provided that, to the extent permitted by applicable law, the Executive shall be credited under such plans or agreements (including plans and agreements of any successor) with two years of additional service with the Company after the Date of Termination for all purposes, including vesting, eligibility and benefit accrual; provided that if the benefit attributable to such service cannot be provided or paid from a tax-qualified plan of the Company, such benefit shall be paid to Executive in a cash lump sum (payable within ten days of the Date of Termination); provided that in no event shall such benefit be duplicated under two or more arrangements.
     (e) Executive’s entitlement to benefits or payments payable under this Section 4 is subject to the Executive’s compliance with Section 7 of this Agreement and subject to the execution and delivery by Executive of a valid and unrevoked Waiver and Release Agreement as required by Section 20.
     5. Full Settlement; Mitigation. The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action that the Company may have against the Executive or others. The Executive shall not be required to mitigate the amount of any payment or benefit provided for in Section 4 hereof by seeking other employment or otherwise, nor (except as specifically provided in Section 4 hereof) shall the amount of any payment or benefit provided for in Section 4 hereof be reduced by any compensation earned by the Executive as the result of employment by another employer or by retirement benefits after the Date of Termination, or otherwise.
     6. Certain Tax Consequences. Whether or not the Executive becomes entitled to the payments and benefits described in Section 4 hereof, if any of the payments or benefits received or to be received by the Executive in connection with a change in ownership or control of the Company (as defined in section 280G of the Code (a “Statutory Change in Control”)) or the Executive’s Termination of Employment (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with the Company, any person whose actions result in a Statutory Change in Control or any person affiliated with the Company or such person) (collectively, the “Severance Benefits”) will be subject to any excise tax (the “Excise Tax”) imposed under section 4999 of the Code, then, subject to Section 6(c), the Company shall pay to the Executive an additional amount equal to the Excise Tax (the “Excise Tax Payment”).
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     For purposes of determining whether any of the Severance Benefits will be subject to the Excise Tax and the amount of such Excise Tax:
     (a) all of the Severance Benefits shall be treated as “parachute payments” within the meaning of Code section 280G(b)(2), and all “excess parachute payments” within the meaning of Code section 280G(b)(1) shall be treated as subject to the Excise Tax, unless, in the opinion of tax counsel selected by the Company’s independent auditors and reasonably acceptable to the Executive, such other payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Code section 280G(b)(4)(A), or such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered, within the meaning of Code section 280G(b)(4)(B), in excess of the “Base Amount” as defined in Code section 280G(b)(3) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax; and
     (b) the value of any non-cash benefits or any deferred payment or benefit shall be determined by the Company’s independent auditors in accordance with the principles of Code section 280G(d)(3) and (4).
     In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder at the time of Termination of Employment of the Executive, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined (the “Reduced Excise Tax”), the difference of the Excise Tax Payment and the Reduced Excise Tax. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder at the time of the Termination of Employment of the Executive (including by reason of any payment the existence or amount of which could not be determined at the time of the Excise Tax Payment), the Company shall make an additional Excise Tax payment in respect of such excess (plus any interest or penalties payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Severance Benefits.
     (c) Notwithstanding any contrary provision of this Agreement, the Severance Benefits shall be reduced to the extent necessary so that no portion of such Severance Benefits shall be subject to the Excise Taxes, but only if the sum of (A) the net amount of such Severance Benefits, without reduction (but after imposition of the total amount of taxes under federal, state and local law) plus (B) the amount of the Excise Tax Payment in respect of such excess plus any interest or penalties payable by the Executive with respect to such excess (but after imposition of the total amount of taxes under federal, state and local law applicable to such additional payment) exceeds the net amount of such Severance Benefits, as so reduced (and after the imposition of the total amount of taxes under federal, state and local law on such amounts or benefits). Any reduction pursuant to this paragraph shall be made by agreement of the parties first from payments and benefits that are exempt from Code Section 409A, and only thereafter from benefits that are subject to Code Section 409A.
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7. Confidential Information; Non-Solicitation; Non-Competition. The Executive shall hold in a fiduciary capacity for the benefit of the Company all secret, proprietary, or confidential materials, knowledge, data or any other information relating to the Company or any of its Affiliates, and their respective businesses (“Confidential Information”), which shall have been obtained by the Executive during the Executive’s employment by the Company or any of its Affiliates and that shall not have been or now or hereafter have become public knowledge (other than by acts by the Executive or representatives of the Executive in violation of this Agreement). During the term of this Agreement and (a) for a period of five years thereafter with respect to Confidential Information that does not include trade secrets, and (b) any time thereafter with respect to Confidential Information that does include trade secrets, the Executive shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any Confidential Information to anyone other than the Company and those designated by it.
     In addition, the Executive shall not, at any time during the term of this Agreement and for a period of two years thereafter (the “Restriction Period”), (a) engage or become interested as an owner (other than as an owner of less than five percent (5%) of the stock of a publicly owned company), stockholder, partner, director, officer, employee (in an executive capacity), consultant or otherwise in any business that is competitive with the uranium enrichment business conducted by the Company or any of its Affiliates during the term of this Agreement or as of the Date of Termination, as applicable, (b) engage in any activity in competition with or against the uranium enrichment business conducted by the Company or any of its Affiliates during the term of this Agreement or as of the Date of Termination, as applicable, or (c) recruit, solicit for employment, hire or engage any employee or consultant of the Company or any of its Affiliates or any person who was an employee or consultant of the Company or any of its Affiliates within two (2) years prior to the Date of Termination. For purposes of this Section 7, a business that is competitive with the uranium enrichment business conducted by the Company or any of its Affiliates shall include, but not be limited to, Louisiana Energy Services Inc. (LES), AREVA SA, AREVA, Inc., Urenco Ltd., Urenco, Inc., Cogema, Enrichment Technology Company Limited, TENEX, GLE (Global Laser Enrichment), Cameco, and any subsidiary or affiliates thereof engaged in a business that is competitive with the uranium enrichment business conducted by the Company or any of its Affiliates, and any contractor or subcontractor to any of these businesses (with respect to activities by such contractor or subcontractor that are competitive with the uranium enrichment business conducted by the Company or any of its Affiliates). The Executive acknowledges that these provisions are necessary for the Company’s protection and are not unreasonable, since he would be able to obtain employment with companies whose businesses are not competitive with the uranium enrichment business of the Company and its Affiliates and would be able to recruit and hire personnel other than employees of the Company or any of its Affiliates. The Executive further acknowledges that these provisions apply even in the absence of a Change in Control. Notwithstanding the foregoing, in the event of a Termination of Employment by the Company without Cause that does not occur following a Change in Control or otherwise during a Protected Period, the restrictions in (a) and (b) above shall apply for the equivalent period of time for which the Executive is offered full salary severance benefits from the Company (e.g., if the Executive is offered severance benefits equal to one times Executive’s annual base salary, the period of time shall be one year); it being understood that under all other circumstances, including a voluntary termination by the Executive that does not occur following a Change in Control or otherwise during a Protected Period, the restrictions in (a) and (b) above shall apply for the full Restriction Period. The duration and the scope of these restrictions on the Executive’s activities are divisible, so that if any provision of this paragraph is held or deemed to be invalid, that provision shall be automatically modified to the extent necessary to make it valid.
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8. Remedies. The Executive acknowledges that a violation or attempted violation on the Executive’s part of Section 7 will cause irreparable damage to the Company, and the Executive therefore agrees that the Company shall be entitled as a matter of right to an injunction, out of any court of competent jurisdiction, restraining any violation or further violation of such promises by the Executive or the Executive’s employees, partners or agents. The Executive agrees that such right to an injunction is cumulative and in addition to whatever other remedies the Company may have under law or equity.
9. Successors; Binding Agreement.
     (a) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company and its subsidiaries to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. As used in this Agreement, “Company” shall mean the Company as defined above and any successor to the business and/or assets of the Company and its subsidiaries that assumes and agrees to perform this Agreement by operation of law, or otherwise. Prior to a Change in Control, the term “Company” shall also mean any Affiliate of the Company to which the Executive may be transferred and the Company shall cause such successor employer to be considered the “Company” and to be bound by the terms of this Agreement and this Agreement shall be amended to so provide. Following a Change in Control the term “Company” shall not mean any Affiliate of the Company to which Executive may be transferred unless Executive shall have previously approved of such transfer in writing, in which case the Company shall cause such successor employer to be considered the “Company” and to be bound by the terms of this Agreement and this Agreement shall be amended to so provide. Failure of the Company to obtain an assumption and agreement as described in this Section 9(a) prior to the effective date of a succession shall be a breach of this Agreement and shall entitle the Executive to compensation from the Company in the same amount and on the same terms as the Executive would be entitled to under this Agreement if the Executive were to terminate the Executive’s employment for Good Reason during a Protected Period, except that, for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the Date of Termination.
     (b) This Agreement shall inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive should die while any amount would still be payable hereunder if the Executive had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Executive’s devisee, legatee or other designee or, if there is no such designee, to the Executive’s estate.
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10. Notices. Any notice, request, instruction or other document given under this Agreement shall be in writing and shall be addressed and delivered, in the case of the Company, to the Secretary of the Company at the principal office of the Company and, in the case of the Executive, to the Executive’s address as shown in the records of the Company or to such other address as may be designated in writing by either party.
11. Withholding Taxes. The Company may withhold from any amounts payable under this Agreement such federal, state and local taxes as may be required to be withheld pursuant to any applicable law or regulation.
12. In-Kind Benefits and Reimbursements. In-kind benefits and reimbursements provided under this Agreement during any tax year of the Executive shall not affect in-kind benefits or reimbursements to be provided in any other tax year of the Executive and are not subject to liquidation or exchange for another benefit. Notwithstanding any other provision of this Agreement, reimbursements must be made on or before the last day of the Executive’s taxable year following the taxable year in which the expense was incurred.
13. Miscellaneous. No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by the Executive and such officer as may be specifically designated by the Board of Directors of the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not expressly set forth in this Agreement.
14. Governing Law; Avoidance of Section 409A Penalty. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to the conflict of laws provisions thereof. Notwithstanding any other provision of this Agreement, in the event of a payment to be made, or a benefit to be provided, pursuant to this Agreement based upon Executive’s Termination of Employment at a time when the Executive is determined to be a Specified Employee by the Committee in its sole discretion and such payment or provision of such benefit is not exempt or otherwise permitted under Section 409A of the Code without the imposition of Section 409A Penalties, such payment shall not be made, and such benefit shall not be provided, before the date which is six (6) months and one day after the Executive’s Termination of Employment. All payments or benefits delayed pursuant to this Section 14 (i) shall be aggregated into one lump sum payment that shall be due and paid on the first day of the seventh month after Executive’s Termination of Employment in accordance with the Company’s normal payroll practices, and (ii) shall not affect any other payments or benefits due under this Agreement.
     This Agreement is intended to be written, administered, interpreted and construed in a manner such that no payment or benefits provided under the Agreement become subject to (a) the gross income inclusion set forth within Code Section 409A(a)(1)(A) or (b) the interest and additional tax set forth within Code Section 409A(a)(1)(B) (together, referred to herein as the “Section 409A Penalties”), including, where appropriate, the construction of defined terms to have meanings that would not cause the imposition of Section 409A Penalties. In no event shall the Company be required to provide a tax gross-up payment to Executive with respect to Section 409A Penalties.
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15. Validity. If any provision of this Agreement shall be declared to be invalid or unenforceable, in whole or in part, such invalidity or unenforceability shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.
16. Counterparts. This Agreement may be signed in several counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
17. Arbitration. Except as otherwise provided in Section 8 hereof, the parties agree that any dispute, claim, or controversy based on common law, equity, or any federal, state, or local statute, ordinance, or regulation (other than workers’ compensation claims) arising out of or relating in any way to this Agreement, its termination or any Termination of Employment, including whether such dispute is arbitrable, shall be settled by arbitration. This agreement to arbitrate includes but is not limited to all claims for any form of illegal discrimination, improper or unfair treatment or dismissal, and all tort claims. The Executive shall still have a right to file a discrimination charge with a federal or state agency, but the final resolution of any discrimination claim shall be submitted to arbitration instead of a court or jury. The arbitration proceeding shall be conducted under the employment dispute resolution arbitration rules of the American Arbitration Association in effect at the time a demand for arbitration under the rules is made. The decision of the arbitrator(s), including determination of the amount of any damages suffered, shall be exclusive, final, and binding on all parties, their heirs, executors, administrators, successors and assigns.
18. Status Prior to Change in Control. Nothing contained in this Agreement shall impair or interfere in any way with the Executive’s right to terminate employment or the right of the Company to terminate the Executive’s employment with or without Cause prior to a Change in Control. Nothing contained in this Agreement shall be construed as a contract of employment between the Company and the Executive.
19. Legal Fees. The Company shall pay the Executive’s reasonable legal fees and expenses that may be incurred by the Executive in contesting or disputing any Termination of Employment that occurs during a Protected Period or in seeking to obtain or enforce any right or benefit provided by this Agreement, if the Executive is the prevailing party (through settlement, arbitration, judicial decision or otherwise) on any material claim in connection with any such dispute.
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20. Waiver and Release. In order to receive benefits or payments under this Agreement, the Executive must execute and deliver to the Company a valid Waiver and Release Agreement in a form tendered by the Company, which shall be substantially in the form of the Waiver and Release Agreement attached hereto as  Exhibit A  and which shall be tendered to the Executive no later than 15 days following the Executive’s Termination of Employment, with any changes thereto approved by the Company’s General Counsel (or in the case of the General Counsel, the Chief Executive Officer) prior to execution. No benefits or payments shall be paid under this Agreement until Executive has executed his or her Waiver and Release Agreement within the time period specified by the Company in the Waiver and Release Agreement (which shall not be more than 45 days after such agreement is tendered to Executive unless otherwise required by law), and the period within which Executive may revoke his or her Waiver and Release Agreement has expired without revocation. Executive may revoke his or her signed Waiver and Release Agreement within seven (7) days (or such other period provided by law) after his or her signing the Waiver and Release Agreement. Any such revocation must be made in writing and must be received by the Company within such seven (7) day (or such other) period. If Executive timely revokes his or her Waiver and Release Agreement, he shall not be eligible to receive any benefits or payments under this Agreement. Notwithstanding the foregoing, if the expiration of the revocation period described above could occur in a calendar year later than the calendar year in which the Waiver and Release Agreement is tendered to the Executive for execution, then in no event will benefits or payments under this Agreement that are conditioned upon the effectiveness of the Waiver and Release Agreement be paid prior to the beginning of such later calendar year.
21. Entire Agreement; Amendment. This Agreement contains the entire understanding of the parties with respect to the subject matter herein and supersedes any prior agreements between the Company and the Executive. There are no restrictions, agreements, promises, warranties, covenants or undertakings between the parties with respect to the subject matter herein other than those expressly set forth herein. This Agreement may be modified or amended only through a writing signed by both parties.
     IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written.
 	 	 	 	 	
 	USEC INC.
 	 	
 	By:  	 	 	
 	 	W. Lance Wright 	 	
 	 	Senior Vice President, Human Resources and Administration 	 	

 	  	 	 	

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EXHIBIT A
WAIVER AND RELEASE
     This is a Waiver and Release (“Release”) between                                          (“Executive”) and USEC Inc. (the “Company”). The Company and the Executive agree that they have entered into this Release voluntarily, and that it is intended to be a legally binding commitment between them.
     1. In consideration for the promises made herein by the Executive, the Company agrees as follows:
     (a) Change in Control Payment. The Company will pay to the Executive payments in the amount set forth in the Change in Control Agreement dated as of ___, _____by and between the Company and Executive (the “Change in Control Agreement”). The Company will also pay Executive accrued but unused vacation pay in the amount of $                      representing _____days of accrued but unused vacation.
     (b) Other Benefits. The Executive will be eligible to receive other benefits as described in the Change in Control Agreement.
     (c) Unemployment Compensation. The Company will not contest the decision of the appropriate regulatory commission regarding unemployment compensation that may be due to the Executive.
     2. In consideration for and contingent upon the Executive’s right to receive the change in control payment and other benefits described in the Change in Control Agreement and this Release, Executive hereby agrees as follows:
     (a) General Waiver and Release. Except as provided in Paragraph 2.(f) below, Executive and any person acting through or under the Executive hereby release, waive and forever discharge the Company, its past and present subsidiaries and affiliates, and their respective successors and assigns, and their respective present or past officers, trustees, directors, shareholders, executives and agents of each of them, from any and all claims, demands, actions, liabilities and other claims for relief and remuneration whatsoever (including without limitation attorneys’ fees and expenses), whether known or unknown, absolute, contingent or otherwise (each, a “Claim”), arising or which could have arisen up to and including the date of his execution of this Release, including without limitation those arising out of or relating to Executive’s employment or cessation and termination of employment, or any other written or oral agreement, any change in Executive’s employment status, any benefits or compensation, any tortious injury, breach of contract, wrongful discharge (including any Claim for constructive discharge), infliction of emotional distress, slander, libel or defamation of character, and any Claims arising under the United States Constitution, the Maryland Constitution, Title VII of the Civil Rights Act of 1964 (as amended by the Civil Rights Act of 1991), the Americans With Disabilities Act, the Rehabilitation Act of 1973, the Fair Labor Standards Act, the Family and Medical Leave Act, the National Labor Relations Act, the Labor- Management Relations Act, the Equal Pay Act, the Older Workers Benefits Protection Act, the Workers Retraining and Notification Act, the Age Discrimination in Employment Act, the Employee Retirement Income Security Act of 1974, Section 211 of the Energy Reorganization Act of 1974, the Maryland Human Rights Act, or any other federal, state or local statute, law, ordinance, regulation, rule or executive order, any tort or contract claims, and any of the claims, matters and issues which could have been asserted by Executive against the Company or its subsidiaries and affiliates in any legal, administrative or other proceeding. Executive agrees that if any action is brought in his or her name before any court or administrative body, Executive will not accept any payment of monies in connection therewith.
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     (b) Miscellaneous. Executive agrees that this Release specifies payment from the Company to himself or herself, the total of which meets or exceeds any and all funds due him or her by the Company, and that he or she will not seek to obtain any additional funds from the Company with the exception of non-reimbursed business expenses. (This covenant does not preclude the Executive from seeking workers compensation, unemployment compensation, or benefit payments from Company’s insurance carriers that could be due him or her.)
     (c) Non-Competition, Non-Solicitation and Confidential Information. Executive warrants that Executive has, and will continue to comply fully with the requirements of the Change in Control Agreement.
     (d) THE COMPANY AND THE EXECUTIVE AGREE THAT THE CHANGE IN CONTROL PAYMENT AND BENEFITS DESCRIBED IN THIS RELEASE AND THE CHANGE IN CONTROL AGREEMENT ARE CONTINGENT UPON THE EXECUTIVE SIGNING THIS RELEASE. THE EXECUTIVE FURTHER UNDERSTANDS AND AGREES THAT IN SIGNING THIS RELEASE, EXECUTIVE IS RELEASING POTENTIAL LEGAL CLAIMS AGAINST THE COMPANY. THE EXECUTIVE UNDERSTANDS AND AGREES THAT IF HE OR SHE DECIDES NOT TO SIGN THIS RELEASE, OR IF HE OR SHE REVOKES THIS RELEASE, THAT HE OR SHE WILL IMMEDIATELY REFUND TO THE COMPANY ANY AND ALL PAYMENTS AND OTHER BENEFITS HE OR SHE MAY HAVE ALREADY RECEIVED PURSUANT TO THE CHANGE IN CONTROL AGREEMENT.
     (e) The waiver contained in Section 2(a) above does not apply to any Claims with respect to:
     (i) Any claims under employee benefit plans subject to the Employee Retirement Income Security Act of 1974 (“ERISA”) in accordance with the terms of the applicable employee benefit plan,
     (ii) Any Claim under or based on a breach of this Release,
     (iii) Rights or Claims that may arise under the Age Discrimination in Employment Act after the date that Executive signs this Release,
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     (iv) Any right to indemnification or directors and officers liability insurance coverage to which the Executive is otherwise entitled in accordance with the Company’s certificate of incorporation or by-laws or an individual indemnification agreement.
     (f) EXECUTIVE ACKNOWLEDGES THAT HE OR SHE HAS READ AND IS VOLUNTARILY SIGNING THIS RELEASE. EXECUTIVE ALSO ACKNOWLEDGES THAT HE OR SHE IS HEREBY ADVISED TO CONSULT WITH AN ATTORNEY, HE OR SHE HAS BEEN GIVEN AT LEAST [45 DAYS — if group layoff] [21 DAYS — if individual termination] TO CONSIDER THIS RELEASE BEFORE THE DEADLINE FOR SIGNING IT, AND HE OR SHE UNDERSTANDS THAT HE OR SHE MAY REVOKE THE RELEASE WITHIN SEVEN (7) DAYS AFTER SIGNING IT. IF NOT REVOKED WITHIN SUCH PERIOD, THIS RELEASE WILL BECOME EFFECTIVE ON THE EIGHTH (8) DAY AFTER IT IS SIGNED BY EXECUTIVE.
BY SIGNING BELOW, BOTH THE COMPANY AND EXECUTIVE AGREE THAT THEY UNDERSTAND AND ACCEPT EACH PART OF THIS RELEASE.

(Executive)	 	 	 	DATE	 	 	
 	 	 	 	 	 	 	 	 	
USEC INC.	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
By:	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	DATE	 	 	
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EXHIBIT 10.37
CHANGE IN CONTROL AGREEMENT
     AGREEMENT (this “Agreement”) by and between USEC Inc., a Delaware corporation (the “Company”) and                        (the “Executive”) dated and effective as of                       , ___.
     WHEREAS, the Executive is currently an employee of the Company;
     WHEREAS, the Board of Directors of the Company has determined that it is essential to the best interests of the Company and its shareholders to foster the continued employment of the Executive, notwithstanding the possibility, threat or occurrence of a Change in Control (as defined in Section 1 hereof) of the Company;
     WHEREAS, the Board of Directors of the Company has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of the Executive in the Executive’s assigned duties without distraction in the face of potentially disturbing circumstances arising from any possible Change in Control of the Company; and
     WHEREAS, the Board of Directors of the Company has concluded that the interests of the Company described above can be best satisfied by agreeing to make certain payments to the Executive if the Executive’s employment is terminated during a protected period prior to or following a Change in Control;
     NOW, THEREFORE, the parties hereto hereby agree as follows:
1. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:
     “Affiliate” shall mean (i) any entity that, directly or indirectly, is controlled by the Company, (ii) any entity in which the Company has a significant equity interest and (iii) an affiliate of the Company, as defined in Rule 12b-2 promulgated under Section 12 of the Exchange Act, in each case as determined by the Committee.
     “Board” shall mean the Board of Directors of the Company or, in the case of any subsidiary of the Company, the board of directors, board of control, board of managers or other governing body of such subsidiary.
     “Cause” shall mean any of the following:
     (i) the engaging by the Executive in willful misconduct that is injurious to the Company or its Affiliates;
     (ii) the embezzlement or misappropriation of funds or material property of the Company or its Affiliates by the Executive, or the conviction of the Executive of a felony or the entrance of a plea of guilty or nolo contendere by the Executive to a felony; or

 
     (iii) the willful failure or refusal by the Executive to substantially perform his or her duties or responsibilities that continues after demand for substantial performance is delivered by the Company to the Executive that specifically identifies the manner in which the Company believes the Executive has not substantially performed his or her duties (other than (a) any such failure resulting from the Executive’s incapacity due to Disability, or (b) any such actual or anticipated failure after the issuance of a Notice of Termination by the Executive for Good Reason).
For purposes of this definition, no act, or failure to act, on the Executive’s part shall be considered “willful” unless done, or omitted to be done, by him or her not in good faith and without reasonable belief that his or her action or omission was in the best interest of the Company. Notwithstanding the foregoing, the Executive’s employment shall not be deemed to have been terminated for Cause unless (A) a reasonable notice shall have been given to him or her setting forth in reasonable detail the reasons for the Company’s intentions to terminate for Cause, and if such termination is pursuant to clause (i) or (iii) above and the damage to the Company or its Affiliates is curable, only if the Executive has been provided a period of ten business days from receipt of such notice to cease the actions or inactions, and he or she has not done so; (B) an opportunity shall have been provided for the Executive together with his or her counsel, to be heard before the Board of Directors of the Company; and (C) if such termination is pursuant to clause (i) or (iii) above, delivery shall have been made to the Executive of a Notice of Termination from the Board of Directors of the Company finding that in the good faith opinion of a majority of the non-management members of the Board of Directors of the Company he or she was guilty of conduct set forth in clause (i) or (iii) above, and specifying the particulars thereof in reasonable detail. Any determination of Cause made by the Company in accordance with the foregoing procedure shall be made by the Company, in its sole discretion. Any such determination shall be final and binding on the Executive.
     “Change in Control” shall mean the following and shall be deemed to have occurred if any of the following events shall have occurred:
     (i) any “Person,” as such term is used in Sections 13(d) and 14(d) of the Exchange Act or Persons acting as a group (other than (A) the Company, (B) any trustee or other fiduciary holding securities under an employee benefit plan of the Company, and (C) any corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of Shares), is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company by reason of having acquired such securities during the 12-month period ending on the date of the most recent acquisition (not including any securities acquired directly from the Company or its Affiliates) representing thirty percent (30%) or more of the total voting power of the Company’s then outstanding voting securities;
     (ii) the majority of members of the Company’s Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Company’s Board before the date of the appointment;
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     (iii) there is consummated a merger or consolidation of the Company or any subsidiary of the Company with any other corporation or other entity, resulting in a change described in clauses (i), (ii), (iv), (v), or (vi) of this definition, other than (A) a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving or parent entity) more than sixty percent (60%) of the total voting power of the voting securities of the Company or such surviving or parent entity outstanding immediately after such merger or consolidation or (B) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no Person, directly or indirectly, acquired forty percent (40%) or more of the total voting power of the Company’s then outstanding securities (not including any securities acquired directly from the Company or its Affiliates);
     (iv) a liquidation of the Company involving the sale to any Person or Persons acting as a group of at least forty percent (40%) of the total gross fair market value of all of the assets of the Company immediately before the liquidation;
     (v) the sale or disposition by the Company or any direct or indirect subsidiary of the Company to any Person or Persons acting as a group (other than any subsidiary of the Company) of assets that have a total fair market value equal to forty percent (40%) or more of the total gross fair market value of all of the assets of the Company and its subsidiaries (taken as a whole) immediately before such sale or disposition (or any transaction or related series of transactions having a similar effect), other than a sale or disposition by the Company or any direct or indirect subsidiary of the Company to an entity, at least sixty percent (60%) of the total voting power of the voting securities of which is beneficially owned by shareholders of the Company in substantially the same proportions as their beneficial ownership of the Company immediately prior to such sale;
     (vi) the sale or disposition by the Company or any direct or indirect subsidiary of the Company to any Person or Persons acting as a group (other than any subsidiary of the Company) of a subsidiary or subsidiaries of the Company credited under GAAP with forty percent (40%) or more of the total revenues of the Company and its subsidiaries (taken as a whole) in the current fiscal year or in any of the two most recently completed fiscal years (or any transaction or related series of transactions having a similar effect), other than a sale or disposition by the Company or any direct or indirect subsidiary of the Company to an entity, at least sixty percent (60%) of the total voting power of the voting securities of which is beneficially owned by shareholders of the Company in substantially the same proportions as their beneficial ownership of the Company immediately prior to such sale; or
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     (vii) a change of the kind described in clauses (i), (ii), (iii), or (iv) of this definition with respect to any Material Subsidiary (with such determination made by replacing “Company” with “Material Subsidiary” in each instance in such clauses); provided, however, that for purposes of applying this provision to clause (i) of this definition, a “Change in Control” shall not be deemed to occur solely as a result of a Person or Persons acting as a group becoming the beneficial owner (as determined under clause (i) of this definition) of less than fifty percent (50%) of the ownership interests of a Material Subsidiary, but shall be deemed to occur if such Person or Persons acting as a group thereafter become the beneficial owner (as determined under clause (i) of this definition) of fifty percent (50%) or more of the ownership interests of such Material Subsidiary.
     “Code” shall mean the Internal Revenue Code of 1986, as amended.
     “Committee” shall mean the Compensation Committee of the Company’s Board of Directors.
     “Disability” shall mean that the Executive has become totally and permanently disabled as defined or described in the Company’s long term disability benefit plan applicable to executive officers as in effect at the time the Executive’s disability is incurred.
     “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended.
     “Good Reason” shall mean, without the Executive’s express written consent, any of the following, unless such act or failure to act is corrected prior to the Date of Termination specified in the Notice of Termination given in respect thereof:
     (i) the Executive is removed from the Executive’s position (with the Company or any Material Subsidiary) as in effect immediately prior to the start of the Protected Period for any reason other than (A) by reason of death, Disability or Retirement or (B) for Cause; provided that such action results in a material diminution of Executive’s authority, duties or responsibilities with the Company and its subsidiaries, taken as a whole;
     (ii) the Executive is assigned any duties inconsistent in a material respect with the Executive’s position (including status, offices, and reporting relationships with the Company or any Material Subsidiary), authority, duties or responsibilities as in effect immediately prior to the start of the Protected Period (or thereafter if increased) if such assignment results in a material diminution of such Executive’s authority, duties or responsibilities with the Company and its subsidiaries, taken as a whole;
     (iii) the Company materially breaches the agreement under which the Executive provides services;
     (iv) the Executive’s annual base salary or annual bonus opportunity (determined on an aggregate basis for the Company and its subsidiaries) as in effect immediately prior to the start of the Protected Period (or thereafter if higher) is materially reduced (except for across-the-board reductions similarly affecting all senior executives of the Company and of any Material Subsidiary and all senior executives of any Person in control of the Company);
     (v) the failure of the Company to obtain an agreement that materially satisfies Section 9 hereof;
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     (vi) any relocation of the Executive’s principal place of business from its location as of the date immediately preceding the start of the Protected Period, by more than fifty (50) miles; or
     (vii) any purported termination of the Executive’s employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 3(b) hereof, which termination for purposes of this Agreement shall be ineffective.
Notwithstanding the foregoing, a termination shall not be treated as a termination for Good Reason unless the Executive shall have delivered a Notice of Termination stating that the Executive intends to terminate employment for Good Reason within ninety (90) days, and such Termination must occur within two years, of the Executive’s having actual knowledge of the initial occurrence of one or more of such events, provided, in each such event, the Company fails to cure within thirty (30) days of receipt of such Notice of Termination. For purposes of this Agreement, any good faith determination of “Good Reason” or good faith determination of the Company’s failure to cure within the thirty (30) day period made by the Executive shall be conclusive.
     “Material Subsidiary” shall mean any subsidiary of the Company (a) whose total assets represent forty percent (40%) or more of the total gross fair market value of all of the assets of the Company and its subsidiaries (taken as a whole) at any time in the current fiscal year or in any of the two most recently completed fiscal years or (b) credited under GAAP with forty percent (40%) or more of the total revenues of the Company and its subsidiaries (taken as a whole) in the current fiscal year or in any of the two most recently completed fiscal years.
     “Protected Period” shall mean the period that begins upon the earlier of (i) three months before the date of any (and each) Change in Control or (ii) the date the Company or any Material Subsidiary enters into a binding agreement with respect to a Change in Control (subject to customary closing conditions), and ends three years after the date of such Change in Control.
     “Retirement” shall mean the Executive’s Separation from Service initiated by the Executive after attainment by the Executive of age sixty-five (65).
     “Section 409A Penalties” shall have the meaning set forth in Section 14 of this Agreement.
     “Specified Employee” shall mean any person described in Section 409A(a)(2)(B)(i) of the Code and Treasury Regulation Section 1.409A-1(i) as determined from time to time by the Committee in its discretion.
     “Shares” shall mean shares of common stock, $0.10 par value, of the Company, or such other securities of the Company as may be designated by the Committee from time to time.
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     “subsidiary” shall mean, with respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with GAAP as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than fifty percent (50%) of the equity or more than fifty percent (50%) of the ordinary voting power or, in the case of a partnership, more than fifty percent (50%) of the general partnership interests are, as of such date, or were, prior to a Change of Control, owned, controlled or held, or (b) that is, or was prior to a Change of Control, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent. For purposes of this paragraph, “Controlled” shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract, or otherwise.
     “Termination of Employment” shall mean and be interpreted in a manner consistent with the definition of “separation from service” within the meaning of Section 409A(a)(2)(A)(i) of the Code and Treasury Regulation Section 1.409A-1(h). The Company retains the right and discretion to specify, and may specify, whether a Termination of Employment occurs for individuals providing services to the Company immediately prior to an asset purchase transaction in which the Company is the seller, who provide services to a buyer after and in connection with such asset purchase transaction; provided, such specification is made in accordance with the requirements of Treasury Regulation Section 1.409A-1(h)(4).
2. Term of Agreement. The term of this Agreement will commence as of the date hereof (the “Effective Date”) and shall continue in effect until the third anniversary of the Effective Date, unless further extended or sooner terminated as hereinafter provided. Commencing on the first anniversary of the Effective Date, and on each anniversary of such date thereafter (each, an “Anniversary Date”), the term shall automatically be extended for one additional year unless the Board of Directors of the Company gives notice to the Executive, at least two months prior to such Anniversary Date, that it does not wish to extend the term. Notwithstanding the foregoing, upon the occurrence of a Change in Control during the term of this Agreement, this Agreement shall continue in effect for a period of three years from the date of such Change in Control, unless sooner terminated as hereinafter provided.
3. Termination During a Protected Period.
     (a) Upon a Termination of Employment during any Protected Period by the Company without Cause, or by the Executive for Good Reason, the Executive shall be entitled to the benefits provided in Section 4 hereof.
     (b) Notice of Termination. Following a Change in Control (and prior thereto if reasonably anticipated to be within a Protected Period), any purported Termination of Employment by the Company or by the Executive shall be communicated by written Notice of Termination to the other party hereto in accordance with Section 10 hereof. For purposes of this Agreement, a “Notice of Termination” shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon, shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated, and shall specify the Date of Termination. The failure by the Executive or the Company to set forth in the Notice of Termination any fact or circumstance that contributes to a showing of Good Reason or Cause shall not waive any right of the Executive or the Company under this Agreement or preclude the Executive or the Company from asserting such fact or circumstance in enforcing the Executive’s or the Company’s rights under this Agreement.
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     (c) Date of Termination. Following a Change in Control (and prior thereto if reasonably anticipated to be within a Protected Period), “Date of Termination” shall mean the date within the term of the Agreement specified in the Notice of Termination, which shall not be less than thirty (30) nor more than sixty (60) days from the date such Notice of Termination is given (except for a termination pursuant to paragraph (v) of the definition of Good Reason, in which event the date upon which any succession referred to therein becomes effective shall be deemed the Date of Termination, or a Termination of Employment by the Company for Cause, in which event the date such notice is received shall be the Date of Termination).
4. Compensation upon Termination without Cause or for Good Reason. Upon any Termination of Employment of the Executive by the Company without Cause (other than because of death, Disability or Retirement), or any Termination of Employment by the Executive for Good Reason, in any case, during any Protected Period, in lieu of any severance benefits Executive would otherwise be eligible to receive under any employment agreement with the Company or any subsidiary or under the Company’s or any subsidiary’s severance plan, if any, as in effect immediately prior to the earlier of the Change in Control or the Executive’s Termination of Employment, the Executive shall be entitled to the following benefits and payments:
     (a) A cash lump sum payment (payable within ten days of the Date of Termination) of full base salary through the Date of Termination at the rate in effect at the time the Notice of Termination is given or, if higher, at the rate in effect immediately prior to the reduction giving rise (pursuant to clause (iv) of the definition of Good Reason) to such termination, plus all other amounts to which the Executive is entitled under any compensation or benefit plan of the Company or any subsidiary at the time such payments are due under the terms of such plans;
     (b) A cash lump sum payment (payable within ten (10) days of the Date of Termination) equal to two and one-half (21/2) times the sum of the Final Salary and the Final Average Bonus. “Final Salary” means the Executive’s annual base salary as in effect on the Date of Termination or, if higher, the Executive’s annual base salary in effect immediately prior to the reduction giving rise (pursuant to clause (iv) of the definition of Good Reason) to such termination. “Final Average Bonus” means the average of the three most recent annual bonuses paid to Executive prior to the Date of Termination, whether such annual bonuses are paid in the form of cash or in grants of restricted common stock of the Company or restricted stock units under the USEC Inc. Annual Incentive Program (which, under the USEC Inc. Annual Incentive Program, generally vests one (1) year after the date of grant);  provided ,  however , that (i) any annual bonus paid to Executive that was pro-rated or otherwise adjusted because Executive was not employed by the Company or any subsidiary during the entire period to which such bonus related shall be annualized for purposes of the calculation of the Executive’s Final Average Bonus; (ii) if Executive has experienced a change in position that has increased Executive’s annual bonus opportunity (whether or not such change in position is accompanied by a change in title), any annual bonus paid to Executive with respect to a period prior to such change in position shall not be included in the calculation of the Executive’s Final Average Bonus; (iii) if Executive shall not have been paid at least three annual bonuses prior to the Date of Termination that are includable in the calculation of Executive’s Final Average Bonus, then Executive’s Final Average Bonus shall be an amount equal to the average of such lesser number of annual bonuses (or, if just one annual bonus, an amount equal to such bonus); and (iv) if Executive shall not have been paid at least one annual bonus prior to the Date of Termination that is includable in the calculation of Executive’s Final Average Bonus, Executive’s Final Average Bonus shall be an amount equal to Executive’s annual target bonus as in effect on the Date of Termination or, if higher, the Executive’s annual target bonus in effect immediately prior to the reduction giving rise (pursuant to clause (iv) of the definition of Good Reason) to such termination. Final Average Bonus shall not include any amount of cash or equity paid or granted as part of any long term incentive plan or program that the Company in its sole discretion may elect to maintain from time to time;
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     (c) Subject to the Executive’s continued compliance with Section 7 hereof and the limitation in Section 12, life, accident and health insurance benefits substantially similar to those that the Executive was receiving immediately prior to the Change in Control (or thereafter, if higher) until the earlier to occur of (i) the 30 month anniversary of the Date of Termination or (ii) such time as the Executive is covered by comparable programs of a subsequent employer.
     (d) In addition to all other amounts payable under this Section 4, the Executive shall be entitled to receive all benefits payable under any other plan or agreement relating to retirement benefits (including plans or agreements of any successor following a Change in Control) in accordance with the terms of such plan or agreement; provided that, to the extent permitted by applicable law, the Executive shall be credited under such plans or agreements (including plans and agreements of any successor) with two and one-half years of additional service with the Company after the Date of Termination for all purposes, including vesting, eligibility and benefit accrual; provided that if the benefit attributable to such service cannot be provided or paid from a tax-qualified plan of the Company, such benefit shall be paid to Executive in a cash lump sum (payable within ten days of the Date of Termination); provided that in no event shall such benefit be duplicated under two or more arrangements.
     (e) Executive’s entitlement to benefits or payments payable under this Section 4 is subject to the Executive’s compliance with Section 7 of this Agreement and subject to the execution and delivery by Executive of a valid and unrevoked Waiver and Release Agreement as required by Section 20.
5. Full Settlement; Mitigation. The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action that the Company may have against the Executive or others. The Executive shall not be required to mitigate the amount of any payment or benefit provided for in Section 4 hereof by seeking other employment or otherwise, nor (except as specifically provided in Section 4 hereof) shall the amount of any payment or benefit provided for in Section 4 hereof be reduced by any compensation earned by the Executive as the result of employment by another employer or by retirement benefits after the Date of Termination, or otherwise.
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6. Certain Tax Consequences. Whether or not the Executive becomes entitled to the payments and benefits described in Section 4 hereof, if any of the payments or benefits received or to be received by the Executive in connection with a change in ownership or control of the Company (as defined in section 280G of the Code (a “Statutory Change in Control”)) or the Executive’s Termination of Employment (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with the Company, any person whose actions result in a Statutory Change in Control or any person affiliated with the Company or such person) (collectively, the “Severance Benefits”) will be subject to any excise tax (the “Excise Tax”) imposed under section 4999 of the Code, then, subject to Section 6(c), the Company shall pay to the Executive an additional amount equal to the Excise Tax (the “Excise Tax Payment”).
     For purposes of determining whether any of the Severance Benefits will be subject to the Excise Tax and the amount of such Excise Tax:
     (a) all of the Severance Benefits shall be treated as “parachute payments” within the meaning of Code section 280G(b)(2), and all “excess parachute payments” within the meaning of Code section 280G(b)(1) shall be treated as subject to the Excise Tax, unless, in the opinion of tax counsel selected by the Company’s independent auditors and reasonably acceptable to the Executive, such other payments or benefits (in whole or in part) do not constitute parachute payments, including by reason of Code section 280G(b)(4)(A), or such excess parachute payments (in whole or in part) represent reasonable compensation for services actually rendered, within the meaning of Code section 280G(b)(4)(B), in excess of the “Base Amount” as defined in Code section 280G(b)(3) allocable to such reasonable compensation, or are otherwise not subject to the Excise Tax; and
     (b) the value of any non-cash benefits or any deferred payment or benefit shall be determined by the Company’s independent auditors in accordance with the principles of Code section 280G(d)(3) and (4).
     In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder at the time of Termination of Employment of the Executive, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined (the “Reduced Excise Tax”), the difference of the Excise Tax Payment and the Reduced Excise Tax. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder at the time of the Termination of Employment of the Executive (including by reason of any payment the existence or amount of which could not be determined at the time of the Excise Tax Payment), the Company shall make an additional Excise Tax payment in respect of such excess (plus any interest or penalties payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Severance Benefits.
     (c) Notwithstanding any contrary provision of this Agreement, the Severance Benefits shall be reduced to the extent necessary so that no portion of such Severance Benefits shall be subject to the Excise Taxes, but only if the sum of (A) the net amount of such Severance Benefits, without reduction (but after imposition of the total amount of taxes under federal, state and local law) plus (B) the amount of the Excise Tax Payment in respect of such excess plus any interest or penalties payable by the Executive with respect to such excess (but after imposition of the total amount of taxes under federal, state and local law applicable to such additional payment) exceeds the net amount of such Severance Benefits, as so reduced (and after the imposition of the total amount of taxes under federal, state and local law on such amounts or benefits). Any reduction pursuant to this paragraph shall be made by agreement of the parties first from payments and benefits that are exempt from Code Section 409A, and only thereafter from benefits that are subject to Code Section 409A.
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7. Confidential Information; Non-Solicitation; Non-Competition. The Executive shall hold in a fiduciary capacity for the benefit of the Company all secret, proprietary, or confidential materials, knowledge, data or any other information relating to the Company or any of its Affiliates, and their respective businesses (“Confidential Information”), which shall have been obtained by the Executive during the Executive’s employment by the Company or any of its Affiliates and that shall not have been or now or hereafter have become public knowledge (other than by acts by the Executive or representatives of the Executive in violation of this Agreement). During the term of this Agreement and (a) for a period of five years thereafter with respect to Confidential Information that does not include trade secrets, and (b) any time thereafter with respect to Confidential Information that does include trade secrets, the Executive shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any Confidential Information to anyone other than the Company and those designated by it.
     In addition, the Executive shall not, at any time during the term of this Agreement and for a period of two and one-half years thereafter (the “Restriction Period”), (a) engage or become interested as an owner (other than as an owner of less than five percent (5%) of the stock of a publicly owned company), stockholder, partner, director, officer, employee (in an executive capacity), consultant or otherwise in any business that is competitive with the uranium enrichment business conducted by the Company or any of its Affiliates during the term of this Agreement or as of the Date of Termination, as applicable, (b) engage in any activity in competition with or against the uranium enrichment business conducted by the Company or any of its Affiliates during the term of this Agreement or as of the Date of Termination, as applicable, or (c) recruit, solicit for employment, hire or engage any employee or consultant of the Company or any of its Affiliates or any person who was an employee or consultant of the Company or any of its Affiliates within two (2) years prior to the Date of Termination. For purposes of this Section 7, a business that is competitive with the uranium enrichment business conducted by the Company or any of its Affiliates shall include, but not be limited to, Louisiana Energy Services Inc. (LES), AREVA SA, AREVA, Inc., Urenco Ltd., Urenco, Inc., Cogema, Enrichment Technology Company Limited, TENEX, GLE (Global Laser Enrichment), Cameco, and any subsidiary or affiliates thereof engaged in a business that is competitive with the uranium enrichment business conducted by the Company or any of its Affiliates, and any contractor or subcontractor to any of these businesses (with respect to activities by such contractor or subcontractor that are competitive with the uranium enrichment business conducted by the Company or any of its Affiliates). The Executive acknowledges that these provisions are necessary for the Company’s protection and are not unreasonable, since he would be able to obtain employment with companies whose businesses are not competitive with the uranium enrichment business of the Company and its Affiliates and would be able to recruit and hire personnel other than employees of the Company or any of its Affiliates.
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The Executive further acknowledges that these provisions apply even in the absence of a Change in Control. Notwithstanding the foregoing, in the event of a Termination of Employment by the Company without Cause that does not occur following a Change in Control or otherwise during a Protected Period, the restrictions in (a) and (b) above shall apply for the equivalent period of time for which the Executive is offered full salary severance benefits from the Company (e.g., if the Executive is offered severance benefits equal to one times Executive’s annual base salary, the period of time shall be one year); it being understood that under all other circumstances, including a voluntary termination by the Executive that does not occur following a Change in Control or otherwise during a Protected Period, the restrictions in (a) and (b) above shall apply for the full Restriction Period. The duration and the scope of these restrictions on the Executive’s activities are divisible, so that if any provision of this paragraph is held or deemed to be invalid, that provision shall be automatically modified to the extent necessary to make it valid.
8. Remedies. The Executive acknowledges that a violation or attempted violation on the Executive’s part of Section 7 will cause irreparable damage to the Company, and the Executive therefore agrees that the Company shall be entitled as a matter of right to an injunction, out of any court of competent jurisdiction, restraining any violation or further violation of such promises by the Executive or the Executive’s employees, partners or agents. The Executive agrees that such right to an injunction is cumulative and in addition to whatever other remedies the Company may have under law or equity.
9. Successors; Binding Agreement.
     (a) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company and its subsidiaries to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. As used in this Agreement, “Company” shall mean the Company as defined above and any successor to the business and/or assets of the Company and its subsidiaries that assumes and agrees to perform this Agreement by operation of law, or otherwise. Prior to a Change in Control, the term “Company” shall also mean any Affiliate of the Company to which the Executive may be transferred and the Company shall cause such successor employer to be considered the “Company” and to be bound by the terms of this Agreement and this Agreement shall be amended to so provide. Following a Change in Control the term “Company” shall not mean any Affiliate of the Company to which Executive may be transferred unless Executive shall have previously approved of such transfer in writing, in which case the Company shall cause such successor employer to be considered the “Company” and to be bound by the terms of this Agreement and this Agreement shall be amended to so provide. Failure of the Company to obtain an assumption and agreement as described in this Section 9(a) prior to the effective date of a succession shall be a breach of this Agreement and shall entitle the Executive to compensation from the Company in the same amount and on the same terms as the Executive would be entitled to under this Agreement if the Executive were to terminate the Executive’s employment for Good Reason during a Protected Period, except that, for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the Date of Termination.
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     (b) This Agreement shall inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive should die while any amount would still be payable hereunder if the Executive had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Executive’s devisee, legatee or other designee or, if there is no such designee, to the Executive’s estate.
10. Notices. Any notice, request, instruction or other document given under this Agreement shall be in writing and shall be addressed and delivered, in the case of the Company, to the Secretary of the Company at the principal office of the Company and, in the case of the Executive, to the Executive’s address as shown in the records of the Company or to such other address as may be designated in writing by either party.
11. Withholding Taxes. The Company may withhold from any amounts payable under this Agreement such federal, state and local taxes as may be required to be withheld pursuant to any applicable law or regulation.
12. In-Kind Benefits and Reimbursements. In-kind benefits and reimbursements provided under this Agreement during any tax year of the Executive shall not affect in-kind benefits or reimbursements to be provided in any other tax year of the Executive and are not subject to liquidation or exchange for another benefit. Notwithstanding any other provision of this Agreement, reimbursements must be made on or before the last day of the Executive’s taxable year following the taxable year in which the expense was incurred.
13. Miscellaneous. No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by the Executive and such officer as may be specifically designated by the Board of Directors of the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not expressly set forth in this Agreement.
14. Governing Law; Avoidance of Section 409A Penalty. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to the conflict of laws provisions thereof. Notwithstanding any other provision of this Agreement, in the event of a payment to be made, or a benefit to be provided, pursuant to this Agreement based upon Executive’s Termination of Employment at a time when the Executive is determined to be a Specified Employee by the Committee in its sole discretion and such payment or provision of such benefit is not exempt or otherwise permitted under Section 409A of the Code without the imposition of Section 409A Penalties, such payment shall not be made, and such benefit shall not be provided, before the date which is six (6) months and one day after the Executive’s Termination of Employment. All payments or benefits delayed pursuant to this Section 14 (i) shall be aggregated into one lump sum payment that shall be due and paid on the first day of the seventh month after Executive’s Termination of Employment in accordance with the Company’s normal payroll practices, and (ii) shall not affect any other payments or benefits due under this Agreement.
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     This Agreement is intended to be written, administered, interpreted and construed in a manner such that no payment or benefits provided under the Agreement become subject to (a) the gross income inclusion set forth within Code Section 409A(a)(1)(A) or (b) the interest and additional tax set forth within Code Section 409A(a)(1)(B) (together, referred to herein as the “Section 409A Penalties”), including, where appropriate, the construction of defined terms to have meanings that would not cause the imposition of Section 409A Penalties. In no event shall the Company be required to provide a tax gross-up payment to Executive with respect to Section 409A Penalties.
15. Validity. If any provision of this Agreement shall be declared to be invalid or unenforceable, in whole or in part, such invalidity or unenforceability shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.
16. Counterparts. This Agreement may be signed in several counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
17. Arbitration. Except as otherwise provided in Section 8 hereof, the parties agree that any dispute, claim, or controversy based on common law, equity, or any federal, state, or local statute, ordinance, or regulation (other than workers’ compensation claims) arising out of or relating in any way to this Agreement, its termination or any Termination of Employment, including whether such dispute is arbitrable, shall be settled by arbitration. This agreement to arbitrate includes but is not limited to all claims for any form of illegal discrimination, improper or unfair treatment or dismissal, and all tort claims. The Executive shall still have a right to file a discrimination charge with a federal or state agency, but the final resolution of any discrimination claim shall be submitted to arbitration instead of a court or jury. The arbitration proceeding shall be conducted under the employment dispute resolution arbitration rules of the American Arbitration Association in effect at the time a demand for arbitration under the rules is made. The decision of the arbitrator(s), including determination of the amount of any damages suffered, shall be exclusive, final, and binding on all parties, their heirs, executors, administrators, successors and assigns.
18. Status Prior to Change in Control. Nothing contained in this Agreement shall impair or interfere in any way with the Executive’s right to terminate employment or the right of the Company to terminate the Executive’s employment with or without Cause prior to a Change in Control. Nothing contained in this Agreement shall be construed as a contract of employment between the Company and the Executive.
19. Legal Fees. The Company shall pay the Executive’s reasonable legal fees and expenses that may be incurred by the Executive in contesting or disputing any Termination of Employment that occurs during a Protected Period or in seeking to obtain or enforce any right or benefit provided by this Agreement, if the Executive is the prevailing party (through settlement, arbitration, judicial decision or otherwise) on any material claim in connection with any such dispute.
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20. Waiver and Release. In order to receive benefits or payments under this Agreement, the Executive must execute and deliver to the Company a valid Waiver and Release Agreement in a form tendered by the Company, which shall be substantially in the form of the Waiver and Release Agreement attached hereto as  Exhibit A  and which shall be tendered to the Executive no later than 15 days following the Executive’s Termination of Employment, with any changes thereto approved by the Company’s General Counsel (or in the case of the General Counsel, the Chief Executive Officer) prior to execution. No benefits or payments shall be paid under this Agreement until Executive has executed his or her Waiver and Release Agreement within the time period specified by the Company in the Waiver and Release Agreement (which shall not be more than 45 days after such agreement is tendered to Executive unless otherwise required by law), and the period within which Executive may revoke his or her Waiver and Release Agreement has expired without revocation. Executive may revoke his or her signed Waiver and Release Agreement within seven (7) days (or such other period provided by law) after his or her signing the Waiver and Release Agreement. Any such revocation must be made in writing and must be received by the Company within such seven (7) day (or such other) period. If Executive timely revokes his or her Waiver and Release Agreement, he shall not be eligible to receive any benefits or payments under this Agreement. Notwithstanding the foregoing, if the expiration of the revocation period described above could occur in a calendar year later than the calendar year in which the Waiver and Release Agreement is tendered to the Executive for execution, then in no event will benefits or payments under this Agreement that are conditioned upon the effectiveness of the Waiver and Release Agreement be paid prior to the beginning of such later calendar year.
21. Entire Agreement; Amendment. This Agreement contains the entire understanding of the parties with respect to the subject matter herein and supersedes any prior agreements between the Company and the Executive. There are no restrictions, agreements, promises, warranties, covenants or undertakings between the parties with respect to the subject matter herein other than those expressly set forth herein. This Agreement may be modified or amended only through a writing signed by both parties.
     IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written.
 	 	 	 	 	
 	USEC INC.
 	 	
 	By:  	 	 	
 	 	W. Lance Wright 	 	
 	 	Senior Vice President, Human Resources and Administration 	 	

 	  	 	 	

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EXHIBIT A
WAIVER AND RELEASE
     This is a Waiver and Release (“Release”) between                                          (“Executive”) and USEC Inc. (the “Company”). The Company and the Executive agree that they have entered into this Release voluntarily, and that it is intended to be a legally binding commitment between them.
     1. In consideration for the promises made herein by the Executive, the Company agrees as follows:
     (a) Change in Control Payment. The Company will pay to the Executive payments in the amount set forth in the Change in Control Agreement dated as of ___, _____by and between the Company and Executive (the “Change in Control Agreement”). The Company will also pay Executive accrued but unused vacation pay in the amount of $                      representing _____days of accrued but unused vacation.
     (b) Other Benefits. The Executive will be eligible to receive other benefits as described in the Change in Control Agreement.
     (c) Unemployment Compensation. The Company will not contest the decision of the appropriate regulatory commission regarding unemployment compensation that may be due to the Executive.
     2. In consideration for and contingent upon the Executive’s right to receive the change in control payment and other benefits described in the Change in Control Agreement and this Release, Executive hereby agrees as follows:
     (a) General Waiver and Release. Except as provided in Paragraph 2.(f) below, Executive and any person acting through or under the Executive hereby release, waive and forever discharge the Company, its past and present subsidiaries and affiliates, and their respective successors and assigns, and their respective present or past officers, trustees, directors, shareholders, executives and agents of each of them, from any and all claims, demands, actions, liabilities and other claims for relief and remuneration whatsoever (including without limitation attorneys’ fees and expenses), whether known or unknown, absolute, contingent or otherwise (each, a “Claim”), arising or which could have arisen up to and including the date of his execution of this Release, including without limitation those arising out of or relating to Executive’s employment or cessation and termination of employment, or any other written or oral agreement, any change in Executive’s employment status, any benefits or compensation, any tortious injury, breach of contract, wrongful discharge (including any Claim for constructive discharge), infliction of emotional distress, slander, libel or defamation of character, and any Claims arising under the United States Constitution, the Maryland Constitution, Title VII of the Civil Rights Act of 1964 (as amended by the Civil Rights Act of 1991), the Americans With Disabilities Act, the Rehabilitation Act of 1973, the Fair Labor Standards Act, the Family and Medical Leave Act, the National Labor Relations Act, the Labor- Management Relations Act, the Equal Pay Act, the Older Workers Benefits Protection Act, the Workers Retraining and Notification Act, the Age Discrimination in Employment Act, the Employee Retirement Income Security Act of 1974, Section 211 of the Energy Reorganization Act of 1974, the Maryland Human Rights Act, or any other federal, state or local statute, law, ordinance, regulation, rule or executive order, any tort or contract claims, and any of the claims, matters and issues which could have been asserted by Executive against the Company or its subsidiaries and affiliates in any legal, administrative or other proceeding. Executive agrees that if any action is brought in his or her name before any court or administrative body, Executive will not accept any payment of monies in connection therewith.
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     (b) Miscellaneous. Executive agrees that this Release specifies payment from the Company to himself or herself, the total of which meets or exceeds any and all funds due him or her by the Company, and that he or she will not seek to obtain any additional funds from the Company with the exception of non-reimbursed business expenses. (This covenant does not preclude the Executive from seeking workers compensation, unemployment compensation, or benefit payments from Company’s insurance carriers that could be due him or her.)
     (c) Non-Competition, Non-Solicitation and Confidential Information. Executive warrants that Executive has, and will continue to comply fully with the requirements of the Change in Control Agreement.
     (d) THE COMPANY AND THE EXECUTIVE AGREE THAT THE CHANGE IN CONTROL PAYMENT AND BENEFITS DESCRIBED IN THIS RELEASE AND THE CHANGE IN CONTROL AGREEMENT ARE CONTINGENT UPON THE EXECUTIVE SIGNING THIS RELEASE. THE EXECUTIVE FURTHER UNDERSTANDS AND AGREES THAT IN SIGNING THIS RELEASE, EXECUTIVE IS RELEASING POTENTIAL LEGAL CLAIMS AGAINST THE COMPANY. THE EXECUTIVE UNDERSTANDS AND AGREES THAT IF HE OR SHE DECIDES NOT TO SIGN THIS RELEASE, OR IF HE OR SHE REVOKES THIS RELEASE, THAT HE OR SHE WILL IMMEDIATELY REFUND TO THE COMPANY ANY AND ALL PAYMENTS AND OTHER BENEFITS HE OR SHE MAY HAVE ALREADY RECEIVED PURSUANT TO THE CHANGE IN CONTROL AGREEMENT.
     (e) The waiver contained in Section 2(a) above does not apply to any Claims with respect to:
     (i) Any claims under employee benefit plans subject to the Employee Retirement Income Security Act of 1974 (“ERISA”) in accordance with the terms of the applicable employee benefit plan,
     (ii) Any Claim under or based on a breach of this Release,
     (iii) Rights or Claims that may arise under the Age Discrimination in Employment Act after the date that Executive signs this Release,
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     (iv) Any right to indemnification or directors and officers liability insurance coverage to which the Executive is otherwise entitled in accordance with the Company’s certificate of incorporation or by-laws or an individual indemnification agreement.
     (f) EXECUTIVE ACKNOWLEDGES THAT HE OR SHE HAS READ AND IS VOLUNTARILY SIGNING THIS RELEASE. EXECUTIVE ALSO ACKNOWLEDGES THAT HE OR SHE IS HEREBY ADVISED TO CONSULT WITH AN ATTORNEY, HE OR SHE HAS BEEN GIVEN AT LEAST [45 DAYS — if group layoff] [21 DAYS — if individual termination] TO CONSIDER THIS RELEASE BEFORE THE DEADLINE FOR SIGNING IT, AND HE OR SHE UNDERSTANDS THAT HE OR SHE MAY REVOKE THE RELEASE WITHIN SEVEN (7) DAYS AFTER SIGNING IT. IF NOT REVOKED WITHIN SUCH PERIOD, THIS RELEASE WILL BECOME EFFECTIVE ON THE EIGHTH (8) DAY AFTER IT IS SIGNED BY EXECUTIVE.
BY SIGNING BELOW, BOTH THE COMPANY AND EXECUTIVE AGREE THAT THEY UNDERSTAND AND ACCEPT EACH PART OF THIS RELEASE.

(Executive)	 	 	 	DATE	 	 	
 	 	 	 	 	 	 	 	 	
USEC INC.	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
By:	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	DATE	 	 	
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EXHIBIT 21
SUBSIDIARIES OF USEC INC.
 	 	 	
Name of Subsidiary	 	State of Incorporation	
 	 	 	
United States Enrichment Corporation
NAC International Inc.	 	Delaware
Delaware	

EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Numbers 333-71635, 333-129410, 333-117867, and 333-150564) and on Form S-3 (File Number 333-146063) of USEC Inc. of our report dated February 24, 2009 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
McLean, Virginia
February 24, 2009

EXHIBIT 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
I, John K. Welch, certify that:
1.	 	I have reviewed this annual report on Form 10-K of USEC Inc.;	
 	 	 	
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	 	
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	 	
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	(a)	 	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	 	 	
 	(b)	 	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	 	 	
 	(c)	 	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	 	 	
 	(d)	 	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	(a)	 	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 	 	 	 	
 	(b)	 	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

February 26, 2009 	/s/ John K. Welch  	 	
 	John K. Welch 	 	
 	President and Chief Executive Officer 	 	

 	 	 	 	 	
EXHIBIT 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
I, John C. Barpoulis, certify that:
1.	 	I have reviewed this annual report on Form 10-K of USEC Inc.;	
 	 	 	
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	 	
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	 	
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	(a)	 	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	 	 	
 	(b)	 	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	 	 	
 	(c)	 	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	 	 	
 	(d)	 	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	(a)	 	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 	 	 	 	
 	(b)	 	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

February 26, 2009 	/s/ John C. Barpoulis  	 	
 	John C. Barpoulis 	 	
 	Senior Vice President and Chief Financial Officer 	 	

 	 	 	 	 	
EXHIBIT 32
Certification of CEO and CFO Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
     In connection with the annual report on Form 10-K of USEC Inc. for the year ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, John K. Welch, President and Chief Executive Officer, and John C. Barpoulis, Senior Vice President and Chief Financial Officer, each hereby certifies, that, to the best of his knowledge:
          (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
          (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of USEC Inc.

February 26, 2009 	/s/ John K. Welch  	 	
 	John K. Welch 	 	
 	President and Chief Executive Officer 	 	

February 26, 2009 	/s/ John C. Barpoulis  	 	
 	John C. Barpoulis 	 	
 	Senior Vice President and Chief Financial Officer 	 	

 	 	 	 	 	
EXHIBIT 99.2
Domestic Company
Section 303A
Annual CEO Certification
As the Chief Executive Officer of USEC Inc. (USU), and as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, I hereby certify that as of the date hereof I am not aware of any violation by the Company of NYSE’s corporate governance listing standards, other than has been notified to the Exchange pursuant to Section 303A.12(b) and disclosed on Exhibit H to the Company’s Domestic Company Section 303A Annual Written Affirmation.
This certification is:
 	 	 	
þ	 	Without qualification	
 	 	 	
 	 	or	
 	 	 	
o	 	With qualification	

By	/s/ John K. Welch	 	 	
 	 	 	 	
Print Name:  	John K. Welch	 	 	
Title:	President and Chief Executive Officer	 	 	
Date:	April 30, 2008	 	 	
[No Exhibit H accompanied the Annual Written Affirmation.]